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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 (FEE REQUIRED)
For the fiscal year ended December 31, 1994
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 (NO FEE REQUIRED) For the transition period from
____________________ to ____________________ Commission file number 0-10201
TGX CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 72-0890264
(State or other jurisdiction (I.R.S. Employer-
of incorporation or organization) Identification No.)
222 Pennbright, Suite 200 Houston, Texas 77090
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (281) 872-0500
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Name of each Exchange
Title of each class on which registered
------------------- ---------------------
Common Stock, $.01 par value Not Applicable
Series A Senior Preferred Stock, $1 par value Not Applicable
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days: Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K/A or any
amendment to this Form 10-K/A: [X]
APPLICABLE ONLY TO REGISTRANTS INVOLVED IN BANKRUPTCY PROCEEDINGS
DURING THE PRECEDING FIVE YEARS: Indicate by check mark whether the registrant
has filed all documents and reports required to be filed by Section 12, 13 or
15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of
securities under a plan confirmed by a court. Yes [X] No [ ]
The aggregate market value of the voting stock held by non-affiliates
as of March 28, 1995 was approximately $25,314.
As of March 28, 1995 there were 25,313,533 shares of Common Stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None
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INDEX
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ITEM PAGE NUMBER
- ---- -----------
PART I.
ITEM 1. BUSINESS ................................................ 1
ITEM 2. PROPERTIES .............................................. 14
ITEM 3. LEGAL PROCEEDINGS ....................................... 14
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS ............................................... 15
PART II.
ITEM 5. MARKET FOR THE REGISTRANT'S SECURITIES AND
RELATED STOCKHOLDERS MATTERS .......................... 16
ITEM 6. SELECTED FINANCIAL DATA ................................. 17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS ......... 18
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ............. 26
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE ................... 49
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ..... 50
ITEM 11. EXECUTIVE COMPENSATION ................................. 52
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT ....................................... 53
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ......... 55
PART IV.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K .................................. 57
SIGNATURES ............................................. 60
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PART I.
ITEM I. BUSINESS
THE COMPANY
General
TGX Corporation ("TGX"), formerly named Templeton Energy, Inc., is a Delaware
corporation that was organized in June 1980. TGX's executive offices are at 222
Pennbright, Suite 200, Houston, Texas 77090 (telephone number 281/872-0500). TGX
(collectively with its subsidiaries, the "Company") is a domestic independent
energy company engaged in the production of oil and natural gas and, to a lesser
degree, in oil and natural gas exploration for its direct account and,
previously, beneficially through general and limited partnerships which were
sold to public and private investors. The Company is also engaged in intrastate
natural gas gathering and treating. TGX commenced operations on July 1, 1981 as
the result of the consummation of an offer in which shares of its common stock
$.01 par value, ("Common Stock"), were issued in exchange for certain interests
in developed and undeveloped oil and natural gas properties held by various
affiliated and unaffiliated entities.
On December 5, 1985, TGX acquired Amarex, Inc.("Amarex") (renamed Temex
Energy, Inc. ("Temex")), an oil and gas exploration company operating primarily
through general and limited partnerships (the "Amarex Partnerships"), in
exchange for the payment of approximately $52,000,000 in cash and the issuance
of 11,475,000 shares of Common Stock to former creditors of Amarex. On August 8,
1988, Temex was merged with and into TGX. Since this acquisition, TGX, as
successor in interest to Temex, has acted as general partner of the Amarex
Partnerships.
From November 1986 through August 1991, TGX, through its then wholly owned
subsidiary LEDCO, Inc. ("LEDCO"), was also engaged in natural gas marketing and,
to a limited degree, providing natural gas transportation services to producers,
local distribution companies and industrial end-users.
On February 22, 1990, TGX filed a voluntary petition in the United States
Bankruptcy Court for the Western District of Louisiana (the "Bankruptcy Court")
for reorganization (the "Reorganization Proceeding") pursuant to Chapter 11
("Chapter 11") of Title 11 of the United States Bankruptcy Code (the "Bankruptcy
Code").
Effective August 31, 1991, TGX sold LEDCO to Ledco Acquisition Company, Inc.,
a company wholly owned by Steinhardt Partners, L.P., a Delaware limited
partnership ("Steinhardt"), and related entities for $2.9 million and the
assignment to TGX by Steinhardt of $2.145 million principal amount of claims
related to TGX's Senior Subordinated Fixed Rate Notes ("Senior Subordinated
Notes").
On January 7, 1992, an Amended Plan of Reorganization (the "Plan") was
confirmed by the Bankruptcy Court and the Plan became effective on January 21,
1992 (the "Effective Date"). On October 2, 1992, the Bankruptcy Court's order of
substantial consummation regarding the Plan became final and non-appealable. For
further information concerning the Plan, see "Reorganization Proceeding" below.
Business Strategy
After substantial consummation of the Plan, and in order to maximize
stockholder value, the Company embarked on a strategy of eliminating non-core
assets, reducing overhead, restructuring its debt and, possibly, capital
structure, and enhancing its productive assets. During 1993 and 1994, a
substantial portion of management's efforts were utilized in implementing the
components of a business plan to effect this strategy.
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In early 1993, the Company relocated and consolidated its offices in Houston,
Texas, thereby reducing expenses and began a program of down-sizing and possibly
out-sourcing certain financial and administrative services. Following the office
consolidation, the Company retained an investment banker to conduct an extensive
review of the Company's operations and assets to determine the most appropriate
means for implementing management's strategy.
The Company's efforts also involved the restructuring and replacing of its
secured long-term debt with the Bank of Montreal ("BMO"), the renegotiation of
its debt with certain persons holding notes arising from administrative claims
incurred during the Reorganization Proceeding, and the program to liquidate and
dissolve substantially all public and private oil and gas drilling and
production purchase programs for which the Company acted as a general partner.
The Company also implemented a program of selling assets which were either
non-core to the Company's strategy or which could provide a significant
immediate cash infusion to relieve debt obligations and long term benefit by
reducing overhead.
As a result of these strategies, in 1994, the Company completed the sale of
substantially all of its oil and gas properties in Ohio and New York to Belden &
Blake Corporation ("BBC") for approximately $16.2 million, restructured its bank
indebtedness as set forth under "Bank Indebtedness," liquidated 17 oil and gas
partnerships and began the process of dissolving and winding up an additional
eight partnerships which will be completed in 1995, and sold approximately 31
partnership properties for $1,424,000 which management believed were non-core to
the Company's strategy. During 1994, the Company was able to reduce its number
of employees from 27 to 13, excluding contract personnel, and its general and
administrative expenses from $3,323,000 to $2,239,000.
In addition to the on-going oil and gas production operations, a key factor in
the Company's future will be the final resolution of the long-standing
litigation (the "NFG Litigation") with National Fuel Gas Distribution
Corporation ("NFG"). While the Company has attempted to commence settlement
negotiations with NFG, to date no meaningful discussions have taken place. If a
settlement cannot be reached, the Company is committed to prosecuting the NFG
Litigation with every reasonable resource available to it. The outcome of the
NFG Litigation, which may be many years away if a settlement cannot be reached,
could materially affect the Company's future. See "Bank Indebtedness" and "NFG
Litigation."
In 1995, the Company will be looking to further reduce its overhead, eliminate
non-core assets, and maximize the return on the assets it retains. It will also
review its current capital structure to determine if a restructuring would
better reflect the Company's financial position. At the same time, the Company
will review growth opportunities consistent with its available capital, to
determine if asset enhancement can be obtained either through drilling or
acquisition. However, given the Company's current financial position and the
inability to predict (i) whether or not any capital restructure will be
effective; (ii) the outcome of the NFG Litigation; and (iii) the success of any
cost reductions, the Company cannot currently determine if it will be able to
successfully implement its business plan and strategy.
Bank Indebtedness
Prior to the Reorganization Proceeding, BMO was TGX's principal secured
lender. At the time of the Chapter 11 filing, TGX owed $29.7 million to BMO (the
"Existing BMO Debt") which was secured by substantially all of TGX's assets. TGX
also guaranteed to BMO certain of the debt of a then wholly owned subsidiary.
Pursuant to the Plan, TGX entered into an Amended and Restated Credit Agreement
(the "Amended Credit Agreement") under which the Existing BMO Debt was continued
and preserved, but was evidenced by new loans ("New BMO Loans"), in the original
aggregate principal amount of approximately $27 million which continued to be
secured by substantially all of TGX's assets and TGX also entered into a
revolving credit agreement for working capital or the issuance of letters of
credit in the maximum amount of $1,000,000. The guaranty of the debt of the
subsidiary was also eliminated.
In early 1993, the Company was notified that Events of Default had occurred
under the Amended Credit Agreement. During 1993, the Company did not cure the
Events of Default and, as a result, BMO had the right to take certain actions
under the Amended Credit Agreement, including, but not limited to, the
acceleration of all of the New BMO Loans.
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In January 1994, in conjunction with the Company's sale of certain assets to
BBC, as described under "Proved Oil and Natural Gas Reserves - Sale of New York
and Ohio Properties", the Company made a debt service payment of approximately
$14.3 million to BMO and entered into a limited forbearance agreement, pursuant
to which, TGX was required to make a payment (the "Required Payment") of $18
million plus accrued interest and fees less (i) the $14.3 million paid to BMO
and (ii) any amounts paid to BMO subsequent to January 1, 1994, that were
applied toward the Required Payment.
On July 13,1994, TGX entered into a series of agreements with BMO and Bank
One, Texas, N.A. ("Bank One") whereby the New BMO Loans were restructured and
all BMO Events of Default resolved. Pursuant to the restructuring, Bank One
established a borrowing-based facility of $2,350,000 under which TGX immediately
borrowed $1,600,000 of which $1,452,000 was paid to BMO in satisfaction of the
remaining amount due of the Required Payment. The Bank One facility bears
interest at Bank One's stated rate plus 2% and is secured by substantially all
of TGX's oil and gas properties. The loan is repayable in 36 months through
monthly principal reductions and the borrowing base is redetermined at a minimum
of every six months or at Bank One's discretion. The Bank One facility requires
the maintenance of certain financial ratios including a working capital ratio of
1.2 to 1 and a tangible net worth of a minimum of $5,000,000 and other ratios.
The Company was in compliance with all financial ratios and covenants at
December 31, 1994, but can give no assurance that it will be able to continually
meet the Bank One ratios.
Simultaneously with the securance of the Bank One facility and payment of the
Required Payment, BMO released all of its liens on TGX's properties with the
exception of its lien on the NFG Litigation. As part of the loan restructuring,
BMO converted $4,652,000 (the "BMOF Principal") of the New BMO Loans, including
fees and expenses, to a non-recourse note secured only by the NFG Litigation and
any proceeds that might be received therefrom. BMO subsequently assigned its
rights to the loan, security and TGX note, to BMO's wholly owned subsidiary, BMO
Financial, Inc. ("BMOF"). Pursuant to agreement, after repayment of the BMOF
Principal, including interest, from NFG Litigation proceeds, if any, BMOF will,
in certain instances, after TGX has received a sum equal to the amount paid to
BMOF, be entitled to receive up to fifty percent interest in certain additional
litigation proceeds. If NFG Litigation proceeds are insufficient to repay the
BMOF Principal, plus applicable interest, TGX will have no further obligation
for such repayment. The BMOF note matures on December 31, 1997, subject to each
party having the right to extend the maturity date, and bears interest at the
rate of 10% per annum. However, until December 31, 1997, and for such further
time as BMOF elects to extend the maturity date of such note, no cash payment
for such interest is required; instead TGX will pay interest in kind through the
issuance of additional notes to BMOF. As of December 31, 1994 total accrued
interest pursuant to the BMOF note was $218,000, resulting in a total year-end
BMOF note balance of $4,870,000.
See Notes 3 and 15 of the Notes to Consolidated Financial Statements.
Administrative Claims
During the Reorganization Proceeding, TGX incurred, and claimants filed
applications for, approximately $7,131,000 in administrative fees and expenses
relating to the reorganization ("Administrative Claims"). TGX objected to
certain of the Administrative Claims and negotiated settlement amounts and terms
of payment with certain holders of Administrative Claims. As a result, each of
these administrative claimants, other than three designated administrative
claimants whose administrative claims were satisfied in a different manner, were
entitled to receive a promissory note (the "Administrative Notes") due December
31, 1994, in satisfaction of each claimant's unpaid Administrative Claim. Such
Administrative Notes were to be issued upon the execution of releases in favor
of the Company and others. Substantially all persons entitled to Administrative
Notes executed such releases. See "Reorganization Proceeding-Overview of the
Plan." The Administrative Notes bore interest at a rate not to exceed 8% and
were secured with certain collateral (the "Consummation Collateral"). If the
proceeds related to the Consummation Collateral were not sufficient to satisfy
the Company's obligations under the Administrative Notes, the Company's excess
operating funds, if any, would be applied toward the balances due. During 1994
and early 1995, the Company renegotiated the terms of substantially all of the
Administrative Notes. As a result, Administrative Notes totaling approximately
$990,000 in principal and $230,000 in accrued interest charges were renegotiated
with the Company making cash payments of $389,000, issuing 141,518 shares of the
Company's Series A Senior Preferred Stock (the "Senior Preferred") and a $90,000
principal amount of non-recourse note payable out of TGX's share of proceeds, if
any, to be received from the NFG
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Litigation. As a result of the Administrative Note renegotiations the Company
reflected an extraordinary net gain of $831,000. Efforts to settle the remaining
outstanding notes on a discounted basis continue.
NFG Litigation
Since November 30, 1984, TGX has been involved in litigation in the United
States District Court for the Western District of New York ("New York Federal
Court") (Civ. No. 84-1372-E) with NFG concerning the validity of a contract (the
"Contract") pursuant to which TGX (as successor-in-interest to Paragon
Resources, Inc. ("Paragon"), the original contracting party) sold certain
natural gas production to NFG. The litigation addresses, among other things, the
validity of the Contract, the price for natural gas sold, and certain take-or-
pay claims.
In December 1983, certain pricing provisions of the Contract were disapproved
by the New York Public Service Commission ("PSC") and as a result, in January
1991, the New York Federal Court determined that the contract was invalidated.
However, on December 3,1991, the Court of Appeals for the Second Circuit ("Court
of Appeals") (Case No. 91 -7127) reversed the New York Federal Court and held
that the Contract remained in effect subject to the pricing provisions set forth
therein. The Court of Appeals remanded the case to the New York Federal Court
for further proceedings not inconsistent with their opinion.
During the Reorganization Proceeding, TGX filed an adversary proceeding (the
"Turnover Proceeding") in the Bankruptcy Court to compel NFG to pay the amount
due to TGX pursuant to the provisions of the Contract. Effective June 19, 1992,
TGX and NFG entered into a partial settlement agreement, regarding the
settlement of some, but not all, of their disputes. Pursuant to the provisions
of the partial settlement agreement, in consideration of a payment of $2,940,000
(the "Payment") from NFG, TGX (i) dismissed the Turnover Proceeding without
prejudice (ii) released NFG (subject to certain limitations) from any and all
liability and affirmative claims for relief alleged to arise from or based upon
certain evidence presented by TGX in the Turnover Proceeding, and (iii) reserved
its rights regarding the assumption or rejection of certain other relatively
minor gas purchase agreements with NFG. The Payment will be credited against any
additional amount due to TGX from NFG.
In July 1992, the New York Federal Court denied a motion filed by NFG for
partial summary judgment wherein NFG sought a finding that it had properly
suspended performance under, and eventually terminated, the Contract. A
subsequent rehearing upheld this conclusion, but determined that certain matters
relating to this issue were questions of fact that cannot be resolved by summary
judgment.
In December 1992, NFG filed a motion with the PSC requesting a hearing to
determine pricing issues related to the Contract. In 1993, the PSC determined
that it would hold the requested hearing, and in November 1994, the
Administrative Law Judge ("ALJ") appointed by the PSC issued a preliminary
Recommended Decision stating that the PSC should find that from December 20,1983
through November, 1992, the maximum contract price that would be just and
reasonable within the meaning of the Public Service Law had been $3.714 per Mcf
of gas. The ALJ also recommended that the Commission should determine only NFG's
entitlement to cost recovery from its customers, and should not adjudicate the
respective rights of TGX and NFG vis-a-vis one another. TGX, NFG and the staff
of the PSC have filed exceptions to the ALJ's recommended rulings, but the PSC
had not ruled on the recommended decision or the filed exceptions as of March 1,
1995.
In January 1993, the New York Federal Court granted TGX's motion for partial
summary judgment regarding the price to be paid under the Contract. Based on the
New York Federal Court's order, TGX has concluded that from December 1983, until
at least, January 1, 1993, the date Federal price controls were terminated, the
Contract price is equal to the lower of (i) the applicable maximum lawful price
for December 1983 and for each month thereafter as established by the Natural
Gas Policy Act ("NGPA") subject to the escalations provided by the NGPA or (ii)
the December 1983 permitted Contract price of approximately $4.41 per MCF. The
Federal Court's decision might be interpreted such that the December 1983
permitted contract price would be $4.41 per Mcf during the winter months and
$4.01 per Mcf during the summer months. Based on TGX's calculations, the gross
difference between the price actually paid by NFG and the price required by the
New York Federal Court's order (assuming a contract price of $4.41 for winter
and $4.01 for summer per Mcf) is approximately $23,912,000 as of December 31,
1994, including permitted statutory interest. The New York Federal Court's order
did not determine the impact of the termination of the NGPA, the effect of any
subsequent PSC order, or NFG's defense, including the alleged repudiation by TGX
of the NFG contract. As part of its sale of substantially all of its oil and gas
properties in Ohio and New York to BBC, TGX assigned the Contract effective
December 1, 1993. TGX's
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assignment of the Contract did not include TGX's rights in its existing claims
against NFG, any proceeds therefrom, and TGX's rights, claims or causes of
action, even if they had not yet been asserted, that arose prior to the
effective time of the assignment.
In November 1994, the New York Federal Court appointed a Magistrate to review
and hear various aspects of the Federal Court litigation, including certain
motions, scheduling, and certain pre-trial discovery. In early 1995, in
anticipation of the issuance of a decision by the PSC in March 1995, the
Magistrate held that all discovery would be stayed pending a further meeting
with the Magistrate in May 1995 to discuss the state of the case.
While TGX is continuing the litigation with NFG regarding the Contract, TGX's
management has determined that it will also continue to seek a negotiated
settlement with NFG. However, there can be no assurances that any such
settlement negotiations will be held or, if held, will be productive. Absent
settlement, TGX will vigorously pursue the NFG Litigation. In either event, the
ultimate result of the litigation or any settlement with NFG could have a
material effect on TGX's financial condition. Also, as a result of the debt
restructuring completed on July 13, 1994, BMO, through its wholly owned
subsidiary, BMOF, is entitled to receive the initial $4,652,000, plus interest,
of any NFG Litigation proceeds and will, in certain instances after TGX has
received the same amount as is paid to BMOF, be entitled to receive up to 50% of
certain additional proceeds. See "Bank Indebtedness." Furthermore, in connection
with the settlement of certain administrative claims, TGX has agreed that
subsequent to the BMOF payment, amounts equal to $90,000 plus interest would be
paid to certain administrative claimants in partial settlement of their
previously outstanding Administrative Notes. See "Administrative Claims." TGX
can make no prediction as to when, if ever, the NFG Litigation will finally be
resolved.
Prior Period Adjustments
In July 1994, the Company restructured and converted its BMO debt of $4,652,000
to a nonrecourse note secured only by proceeds, if any, which might be
received from the NFG Litigation. This restructuring and conversion was
accounted for as an exchange transaction presented as an extinguishment of debt
in accordance with Emerging Issues Task Force Consensus No. 86-18 and resulted
in the recognition of an extraordinary gain, net of transaction costs of
$492,000, of $4,160,000 in the third quarter of 1994. In connection with
responding to comments from the Securities and Exchange Commission in connection
with a 1996 filing, the Company accepted the securities and Exchange
Commission's determination that generally accepted accounting principles require
the Company to account for the restructuring and conversion of debt as a
troubled debt restructuring in accordance with Statement of Financial Accounting
Standards No. 15. As a result of this change, the financial statements for
September 30, 1994 through the current reported period have been restated to
restore the liability for the nonrecourse BMO debt, including accrued interest,
and to reverse the extraordinary gain recognized in 1994. This restatement did
not impact cash flow during the period September 30, 1994 through the current
reported period. The Company did, however, upon resolution of the NFG
Litigation in April 1996, reflect a net gain from litigation settlement of
$7,100,000 and an extraordinary debt extinguishment gain of $1,868,000, and
made a final debt payment to BMO of $3,600,000. See Note 15 of the Notes to
Consolidated Financial Statements.
Fresh Start Reporting
As a result of the substantial consummation of the Plan and due to (i) the
reallocation of the voting rights of equity interest owners and (ii) the
reorganization value of TGX's assets being less than the total of all of its
post-petition liabilities and allowed claims, as of October 2, 1992, the effects
of the Reorganization Proceeding were accounted for in accordance with the fresh
start reporting standards promulgated under the American Institute of Certified
Public Accountants Statement of Position 90-7 "Financial Reporting by Entities
in Reorganization Under the Bankruptcy Code" ("SOP 90-7").
In conjunction with implementing fresh start reporting, the Company's
management determined a reorganization value ("RV") which attempted to establish
the fair market value of the Company as of the date of substantial consummation
of the Plan. Oil and gas property and other related asset values were estimated
by discounting future net revenues on the basis of actual, or in some instances,
assumed prices. Other assets were valued at their book value. The Company's
Senior Preferred Stock, which was issued pursuant to the Plan, was determined on
the basis of the difference between the RV of the Company's assets less the
present value of
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liabilities and the par value of preconsummation equity interests. For further
information concerning the method of calculating the RV, see Note 2 of the Notes
to Consolidated Financial Statements.
The RV was determined by management on the basis of its best judgment of what
it considered to be the fair market value ("FMV") of the Company's assets and
liabilities after reviewing relevant facts concerning the price at which similar
assets were being sold between willing buyers and sellers. However, there can be
no assurances that the RV and the FMV are comparable and the difference between
the Company's calculated RV and the FMV may, in fact, be material.
In conjunction with the implementation of fresh start reporting, the Company
also adopted the successful efforts method, rather than the full cost method, of
accounting for oil and natural gas properties. In the opinion of the Company's
management, this accounting method was preferable since it would result in a
better matching of oil and natural gas revenues with the related exploration and
production costs and expenses. See Note 1 to Notes to Consolidated Financial
Statements.
REORGANIZATION PROCEEDING
Overview of the Plan
The following is a brief summary of certain information regarding the Plan.
The summary is necessarily incomplete and selective and is qualified in its
entirety by reference to the Plan, the full terms of which are hereby
incorporated by reference.
Pursuant to the Plan, the Company entered into the Amended Credit Agreement
with BMO, and, depending on the amount of the claim, satisfied unsecured claims
with cash or Senior Preferred Stock. See "The Company -Bank Indebtedness", and
Terms of Preferred and Common Stock". In addition, certain specified classes of
claims were paid in cash, retained or otherwise provided for. Administrative
claimants holding allowed Administrative Claims under the Plan were paid in cash
or had their claims otherwise satisfied, and, numerous executory contracts were
assumed or rejected by TGX. See "The Company -Administrative Claims." Currently,
the aggregate balance of pre-petition obligations related to assumed executory
contracts is approximately $317,000 which is related to undistributed net oil
and gas revenues and which is in a "suspended pay" status.
As of the Effective Date of the Plan, the preferred and common stockholders
selected a new Board of Directors (the "New Board") comprised of eight
individuals to serve until January 1995, or until their successors were duly
elected and qualified. The New Board consisted of five members selected by
holders of the Senior Preferred (two of which were designees of Steinhardt, and
one of which could not be an affiliate of any holder of the Senior Preferred)
and two members selected by holders of the other classes of stock acting as one
class. The remaining member of the New Board was the chief executive officer of
the Company. Subsequent to the Effective Date, two members of the Board of
Directors have resigned and have not been replaced. See "Item 10. Directors and
Executive Officers of the Registrant". While the existing Board of Directors
will retain their positions until their successors are duly elected and have
qualified, subsequent to January 21, 1995, the Board's structure was no longer
fixed by the Plan and as a result when new directors are elected, the Plan
provides that eight directors are to be elected without regard to class
representation. However, holders of Senior Preferred have 95% of the voting
power of the Company and a plurality of such holders can, therefore effectively
elect all Directors. In addition, two additional directors are to be elected
solely by the Senior Preferred Stockholders until the Company has made up its
dividend arrearages. See "Unsecured Claims -Senior Preferred."
Administrative Expenses
During the Reorganization Proceeding, certain claimants filed applications for
Administrative Claims of approximately $7,131,000 in administrative fees and
expenses related to the Reorganization Proceeding. Three of the large
administrative claimants (the "Opposing Administrative Claimants") agreed that
in consideration for the satisfaction in full of the balance of their
Administrative Claims as of the date of substantial consummation they would
receive (i) a payment of $300,000 (ii) 55,000 shares of the Senior Preferred and
(iii) the conveyance of approximately 29,400 acres of undeveloped land in
Culberson and Hudspeth Counties, Texas. For information concerning the payment
of other Administrative Claims see "Business of the Company-Administrative
Claims".
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Unsecured Claims
General
Pursuant to the Plan, the Company has designated a Series A Senior Preferred
Stock ($1 par value) and a Series B Preferred Stock ($1 par value) ("Junior
Preferred") to be issued to holders of certain classes of claims and retains its
Old Preferred and Common Stock. The total number of authorized shares of Senior
Preferred is 10,000,000.
Senior Preferred
The Plan provides for a total of 8,529,246 shares of Senior Preferred to be
issued to holders of certain unsecured claims on the basis of one share of
Senior Preferred for every $10 of certain finally allowed or otherwise agreed
upon claim. The Senior Preferred entitles its holders to receive a 10% annual
compounded cash dividend, payable quarterly, provided however, that the payment
of such dividend does not violate Delaware law or certain covenants in the
Company's bank loan agreements. At any time after January 21, 1995, whenever
quarterly dividends payable on the Senior Preferred are in arrears in an
aggregate amount equal to six full quarterly dividends (which need not be
consecutive), the number of directors of the Company is increased by two and
such additional directors are elected by the holders of the Senior Preferred at
the next succeeding annual meeting of stockholders (and at each succeeding
annual meeting of stockholders thereafter until such right shall terminate as
provided pursuant to the Plan). The Company has not paid any of the quarterly
dividends required since the Effective Date of the Plan and, based on the
current financial position of the Company, it does not expect to make any such
dividend payments in the near future. See "Overview of the Plan."
The Senior Preferred is being issued without registration under the Securities
Act of 1933, as amended (the "Securities Act") in reliance upon the exemption
from registration available under Section 1145 of the Bankruptcy Code.
Holders of Senior and Junior Preferred have a liquidation preference in the
amount of $10 per share, with the holders of Senior Preferred having priority
over the liquidation preference afforded the holders of Junior Preferred, Old
Preferred and Common Stock. At the option of the Company, the Senior and Junior
Preferred are redeemable in whole or in part at any time at a price per share
equal to the liquidation preference amount per share, plus all accrued and
unpaid dividends through the date of redemption. The Company must redeem all
outstanding shares of the Senior Preferred at the full redemption price on or
before ten years from the Effective Date of the Plan unless such redemption
would violate Delaware law, in which case the Company must redeem the Senior
Preferred as soon as it is possible in accordance with Delaware law.
Holders of Senior Preferred have 95% of the voting rights of TGX with the
remaining 5% of voting rights being allocated collectively among holders of the
Junior Preferred, Old Preferred and Common Stock (herein collectively called the
"Other Stock").
In connection with the distribution of the Senior Preferred Stock to claimants
holding Senior Subordinated Notes, the Bank of New York ("BONY"), as indenture
trustee pursuant to the indenture defining the rights of the holders of the
previously outstanding Senior Subordinated Notes, alleged that it was entitled
to collection of certain fees and expenses under the Plan. Such fees and
expenses were disputed by TGX and certain of the holders of Senior Subordinated
Notes. In late 1994, a compromise was effected with BONY whereby TGX has paid to
BONY the sum of $90,000 in full settlement of BONY's claims. As a result, BONY
has commenced a process of distributing the Senior Preferred.
Junior Preferred Stock
Any claimants entitled to receive shares of Junior Preferred receive one share
of Junior Preferred for every $10 of finally allowed claim. To date, no claims
to be satisfied by Junior Preferred have been finally allowed and the Company
does not currently anticipate that any such claims will be finally allowed.
7
<PAGE>
Old Preferred Stock
The 300,000 shares of Old Preferred, $1 par value with a liquidation
preference of $10 per share, ranks junior in preference and priority to Senior
Preferred. Subject to the prohibitions of Delaware law and the Amended Credit
Agreement, Old Preferred receives dividends at the rate of 9% per annum
beginning on the Effective Date of the Plan, payable annually on the first
business day of January of each year, with such dividends being paid in
additional shares of Old Preferred until the Senior Preferred is redeemed in
full. To date, no dividends related to the Old Preferred have been declared or
paid. Subsequent to their sale of LEDCO to TGX, Gaylon D. Simmons and Gloria
Annette Turner Simmons (collectively, "Simmons"), the former owners of LEDCO,
have been engaged in a series of lawsuits against TGX and certain other parties.
Pursuant to the Plan, Simmons will not seek recoveries against the Company in
this litigation. In addition, any recoveries by Simmons from other parties,
after a reduction for Simmons' reasonable attorneys' fees and costs plus
interest, will result in the cancellation of securities issued to Simmons to the
extent necessary to assure that Simmons' treatment under the Plan does not
result in a double recovery on identical causes of action.
The Old Preferred may be converted in whole, at any time, or in part, from
time to time, at the option of the holder thereof into fully paid and non-
assessable shares of Common Stock at the conversion rate of four shares of
Common Stock for each share of Old Preferred.
Common Stock
The Company is authorized to issue 100,000,000 shares of Common Stock, of
which 25,313,533 shares were outstanding as of March 1, 1995. All outstanding
shares of the Common Stock are fully paid and non-assessable.
The holders of Common Stock are entitled to one vote per share upon all
matters presented to them. Pursuant to the Plan, holders of Common Stock are
entitled, collectively with holders of Junior Preferred and Old Preferred, to 5%
of the total voting power of the Company. The holders of Common Stock are
entitled to dividends in such amounts as may be declared from time to time out
of any funds legally available for such purposes. However, no dividends are
payable until all accrued dividends have been paid to the preferred
stockholders. In the event of liquidation, dissolution or winding up of the
affairs of the Company, whether voluntary or involuntary, after payment of debts
and liquidation preferences on preferred stock, all remaining assets, if any,
will be divided and distributed among the holders of Common Stock pro rata
according to the number of shares owned by them. The Common Stock does not have
preemptive rights and is not subject to redemption.
Jurisdiction of Bankruptcy Court
The Plan provides that the Bankruptcy Court retains jurisdiction after the
confirmation date for certain matters including, but not limited to, (i)
modifying the Plan pursuant to the Bankruptcy Code, (ii) assuring the
performance by TGX under the Plan, (iii) enforcing and interpreting the terms
and conditions of the Plan, (iv) entering into such orders, including
injunctions, as are necessary to enforce the title, rights and powers of TGX and
to impose such limitations, restrictions, terms and conditions of such title,
rights and powers as the Bankruptcy Court may deem necessary and, (v) deciding
issues concerning federal tax reporting and withholding which arise in
connection with the confirmation of the Plan.
BUSINESS SEGMENT INFORMATION
The only segment in which the company operates is the development and
production of, and to a lesser degree the exploration for, oil and natural gas
plus intrastate natural gas gathering and treating.
General Conditions in the Oil and Gas Industry
In recent years, the natural gas industry has experienced the adverse effects
of domestic recessions, increased conservation measures and mild winter weather
which has resulted in lower demand and a corresponding precipitous decrease in
natural gas prices. The current NYMEX natural gas future contract price for the
delivery month of April 1995 is $1.46/MMBTU as compared to $2.00/MMBTU for the
same period in 1994. As a result of weather, availability of alternative fuels
and natural gas surplus in storage, the price for natural gas may continue to
have downward price pressures in the near term. As of March 1, 1995, the per
barrel future price
8
<PAGE>
for West Texas Intermediate oil production ("WTI"), which serves as the
benchmark for domestic oil prices, was $16.75 as compared to $13.00 for the same
date in 1994. Though oil prices are currently higher than the prior year, the
price continues to fluctuate significantly. The uncertainty in the oil and
natural gas industry over the duration and extent of economic and political
conditions have adversely affected the industry. These conditions, added to
other factors particularly affecting TGX, have adversely affected the business
of the Company.
Oil and Gas Exploration and Production
The Company's principal activity is the production of oil and natural gas. In
recent years the Company has reduced its oil and natural gas exploration and
property acquisition activities due to reduced oil and natural gas prices and
its financial condition. The Company continues to maintain a staff of
professional and support personnel required to manage its existing properties,
including one geologist, two engineers, and three marketing and land personnel.
In addition, the Company has engaged petroleum geologists and engineers on a
contract basis, as required.
Proved Oil and Natural Gas Reserves
Reserves and Reserve Values
(a) General:
Estimating economically recoverable crude oil and natural gas reserves and the
future net revenues therefrom is not an exact science and is based upon a number
of variable factors, such as historical production of the subject properties as
compared with similar producing properties, and assumptions such as the effects
of regulation by governmental agencies, future taxes, and development and other
costs, all of which may vary considerably from actual results. All such
estimates are to some degree speculative, and classifications of reserves are
only attempts to define the degree of speculation involved. For these reasons,
estimates of economically recoverable reserves of crude oil and natural gas
attributable to any particular group of properties, the classification and risk
of recovering such reserves, and estimates of the future net revenues expected
therefrom, prepared by different engineers or by the same engineers at different
times, may vary substantially.
Proved oil and natural gas reserves are the estimated quantities of crude oil,
natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Estimates
with respect to proved undeveloped and proved developed non-producing reserves
that may be developed and produced in the future are based upon volumetric
calculations or upon analogy to similar types of reservoirs. Later studies of
the same reservoirs based upon production history may result in variations,
which may be substantial. The actual production, revenues, severance and excise
taxes, development costs, and operating expenditures with respect to the
Company's reserves as reflected herein may vary from estimates, and such
variances may be material.
Based on the independent petroleum engineering report of Netherland, Sewell &
Associates, Inc., as of January 1, 1995, utilizing year end product prices and
costs held constant, the Company's proved oil and natural gas reserves in
thousands of barrels ("MBbls") and billion of cubic feet ("BCF"), and associated
estimated future net revenues, undiscounted and discounted at 10% ("PV 10"), are
as follows (dollars in thousands):
Estimated Future Net Revenues
-----------------------------
Oil (MBbls) Gas (Bcf) Undiscounted PV10
----------- --------- ------------ ----
Proved developed 444 7.8 $ 9,571 $ 6,594
Proved undeveloped 487 2.6 5,243 2,213
- --------------------------------------------------------------------------------
Total proved reserves 931 10.4 $14,814 $ 8,807
================================================================================
Due to TGX's financial condition, prior year disclosures utilized only proved
developed reserves because of to the uncertainty regarding TGX's ability to
develop proved undeveloped reserves. As a result of TGX's debt restructuring
(See "Indebtedness" above) and anticipated 1995 cash flow, TGX has included
proved undeveloped reserves in preparing the 1994 report disclosures. The
addition of the proved undeveloped reserves
9
<PAGE>
is reflected as 1994 extensions and discoveries. All prior year reserve
disclosures continue to be reported utilizing only proved developed reserves.
See Note 12 of the Notes to Consolidated Financial Statements for a discussion
of the calculation of the estimated future net revenues on an undiscounted and
discounted basis.
(b) Sale of New York and Ohio Properties:
In January 1994, but effective as of December 1, 1993, the Company sold
substantially all of its New York and Ohio properties (the "Sold Properties") to
BBC for $16.2 million. In conjunction with this transaction, the Company
assigned to BBC the Company's contract with NFG, pursuant to which a substantial
portion of the Company's natural gas underlying the Sold Properties was
marketed. The assignment of the NFG Contract was made with certain reservations
relating to the NFG Litigation. At the time of the sale, BMO released its liens
on the Sold Properties and the proceeds from the sale were used to repay a
substantial portion of the Company's debt to BMO. See "Bank Indebtedness" above.
(c) Tabular Information:
The table below sets forth an analysis of the change in the Company's proved
oil and natural gas reserves during 1994:
Oil(MBbls) Gas(Bcf)
- --------------------------------------------------------------------------------
Estimated proved developed reserves
as of December 31, 1993 525 9.1
Sale of reserves in place (37) (0.5)
Extensions and discoveries (1) 487 2.6
Revisions of previous estimates 18 1.4
Production (62) (2.2)
- --------------------------------------------------------------------------------
Estimated proved reserves as of December 31, 1994 931 10.4
================================================================================
(1) Reflects inclusion of proved undeveloped reserves that had been excluded
in prior years' reporting.
Except for the data contained in filings with the Securities and Exchange
Commission ("SEC") and information furnished in conjunction with the
Reorganization Proceeding pursuant to the order of the Bankruptcy Court, the
Company has not filed information relating to estimates of its proved oil and
natural gas reserves with any federal agencies.
Oil and Gas Production
Information pertaining to the Company's oil and natural gas production is set
forth in the table below.
Year Ended December 31,
-----------------------
1994 1993 1992
- --------------------------------------------------------------------------------
Oil production (MBbls) 62 87 82
Average price per barrel $ 15.16 $ 17.03 $ 19.40
Natural gas production (Bcf) 2.241 3.712 3.545
Average price per Mcf $ 1.72 $ 2.22 $ 2.13
Equivalent Mcf (6:1) 2.613 4.234 4.037
Lease operating expense
per equivalent Mcf $ 1.22 $ .93 $ .98
Net oil and natural gas revenues (in thousands):
Sale of production $ 4,802 $ 9,730 $ 9,142
Lease operating expenses (3,188) (3,935) (3,968)
- --------------------------------------------------------------------------------
Net oil and natural gas revenues $ 1,614 $ 5,795 $ 5,174
================================================================================
10
<PAGE>
Drilling Activity
For the past three years, the Company has participated in no significant
drilling operations.
Leasehold Acreage and Productive Wells
The following table sets forth the Company's interest in undeveloped acreage,
developed acreage and productive wells in which it owns a working interest.
Undeveloped Developed Productive
Acreage Acreage Wells /1/
----------- ---------- ------------
Gross Net Gross Net Gross Net
- --------------------------------------------------------------------------------
Arkansas 50 31 2,760 1,355 41 15
Louisiana 0 0 4,712 535 12 1
Oklahoma 316 263 75,419 3,733 186 7
Texas 0 0 16,895 713 70 3
Other states 0 0 27,905 1,480 639 3
- --------------------------------------------------------------------------------
Total 366 294 127,691 7,816 948 29
================================================================================
/1/ Productive wells are wells capable of producing oil or natural gas in
economic quantities.
The following table provides, as of December 31 for each year presented below
with the Sold Properties being excluded for 1993 and 1994, additional
information pertaining to the productive wells in which the Company owns a
working interest.
Gross /1/ Net /2/
-----------------------------------------------------
Oil Gas Total Oil Gas Total
- --------------------------------------------------------------------------------
1992 844 1,407 2,251 23 932 955
1993 756 276 1,032 19 26 45
1994 771 177 948 17 12 29
- --------------------------------------------------------------------------------
/1/ "Gross" wells are the total number of wells in which the Company owns an
interest.
/2/ "Net" represents the Company's working interest in each "Gross" well.
A Summary of the Sold Properties is:
Developed Productive
Acreage Wells
- --------------------------------------------------------------------------------
Gross Net Gross Net
----- --- ----- ---
Louisiana 1,635 93 3 1
New Mexico 80 5 2 0.5
New York 13,123 449 117 4
Oklahoma 160 160 1 1
Texas 3,097 385 19 1
- --------------------------------------------------------------------------------
Total 18,095 1,092 142 7.5
================================================================================
Partnerships
Prior to 1985, the Company was actively engaged in the formation of limited or
general partnerships structured to (i) drill for-oil-and natural gas or (ii)
acquire oil and natural gas producing properties. In 1985, the Company acquired
Amarex which was engaged in oil and natural gas exploration and production for
its own
11
<PAGE>
account and beneficially through the Amarex Partnerships. The Company liquidated
17 partnerships during 1994, due to such partnerships' financial condition and
limited reserve values. As a result of the 1994 partnership liquidations the
Company, as settlement of outstanding partnership notes and receivable, was
assigned additional direct interests in related oil and natural gas properties
having an estimated value of $381,000 and realized from such sales recoupment of
$751,000 in previous allowed for receivables and notes.
At December 31, 1994, the Company served as the managing general partner of
eight oil and natural gas partnerships. TGX intends to pursue the liquidation of
substantially all of the remaining partnerships during 1995. The liquidation of
these partnerships could result in liquidating cash distributions to TGX and the
collection of other amounts due to TGX from the partnerships. In addition, TGX
will be able to reduce certain of its administrative expenses as a result of the
liquidation of the partnerships.
Natural Gas Treating Plant
Through a joint venture, the Company owns an interest in a natural gas
treating plant located in the Comite Field, East Baton Rouge Parish, Louisiana.
Natural gas from two wells operated by the Company and one well operated by a
third party is currently transported to the plant where it is treated to satisfy
pipeline specifications. The plant also provides condensate handling and
saltwater disposal facilities. The Company receives cash distributions from the
joint venture for its share of net cash flow. For information concerning this
treating plant, see Note 5 of the Notes to Consolidated Financial Statements.
Competition, Markets and Other External Factors
Competition and Marketing -Oil and Natural Gas Industry
The oil and natural gas industry is highly competitive both in the search for
and acquisition of oil and natural gas reserves and in the refining, processing
and marketing of petroleum products. Competitors include the major and
independent crude oil and natural gas companies, individual producers and
operators, and major pipeline companies. Other sources of energy, such as coal
and nuclear power, also provide competition, and crude oil and natural gas are
subject to substantial competition from foreign sources.
The price the Company receives for its oil production depends on many
variables over which it has no control, such as the world supply of, and demand
for, oil, the level of imports, and the political stability of foreign
governments. The influence exerted by these and other factors has caused
domestic oil prices to fluctuate dramatically.
The availability of a ready market as well as the price received for natural
gas produced and sold by the Company also depends upon numerous factors beyond
its control, including the proximity of producing natural gas properties to
pipelines, the capacity of such pipelines' fluctuations in seasonal or overall
demand, domestic deliverability, government regulations, and competition from
alternative forms of energy.
Major Customers
Information concerning sales to customers who accounted for more than 10% of
total revenues, the loss of any of which could have a material adverse effect on
the Company's operations if alterative customers could not be found, is
contained in Note 11 of the Notes to Consolidated Financial Statements appearing
elsewhere herein. As a result of the sale of properties to BBC, the Company no
longer has any significant natural gas sales to NFG.
Production and Development Hazards
Hazards such as unexpected formations, blow-outs, cratering and fires are
involved in crude oil and natural gas drilling, production and development
activities. Such hazards, as well as adverse weather conditions, may hinder or
delay drilling and development operations. TGX maintains insurance coverage
customary in the crude oil and natural gas industry, but may be subject to
liability for pollution and other damages or may lose substantial portions of
its properties due to hazards against which it is impossible or impractical (due
to prohibitive premium requirements) to maintain insurance. Governmental
regulations relating to environmental matters could also increase TGX's cost of
production and development operations or require it to cease production and
development operations in certain areas.
12
<PAGE>
Regulation
Environmental Regulation
The drilling for, production, transportation and storage of oil and natural
gas and the operation and maintenance of natural gas treating plants are subject
to various federal and state laws and regulations designed to protect the
environment. Moreover, various state and governmental agencies are considering,
and some have adopted, other laws and regulations regarding environmental
control which could adversely affect the business of the Company. Compliance
with such legislation and regulations, together with any penalties resulting
from noncompliance therewith, may increase the cost of the Company's operations
or may affect the Company's ability to complete, in a timely fashion, existing
or future activities. However, the Company does not believe that such
regulations could materially and adversely affect its financial condition or
operations at the present time.
State Regulation
All states in which the Company conducts oil and natural gas production
operations have statutory provisions regulating the drilling for, production,
transportation, storage and sale of oil and natural gas. Such statutes, and the
regulations promulgated in connection therewith, generally are intended to
prevent the waste of oil and natural gas and to protect correlative rights and
opportunities to produce oil and natural gas as between owners of interests in a
common reservoir. Certain state regulatory authorities also regulate the amount
of oil and natural gas produced by assigning allowable rates of production to
each well or proration unit.
Federal Regulation
The Company's sale of its natural gas has historically been regulated by the
Federal Energy Regulatory Commission ("FERC") under the authority of the Natural
Gas Policy Act of 1978, which established price controls for various
classifications of gas. However, as a result of the Wellhead Decontrol Act of
1989, all price controls were terminated as of January 1, 1993. The Company
believes that this has had little or no impact on its natural gas sales, since
its reserves were either previously deregulated, or sold under contracts with
alternate pricing.
FERC Order No. 636, revised to 636-B in November, 1992, ("Order 636") may
however, have an impact on the Company's natural gas sales. Order 636 is a
restructuring rule applicable to interstate pipelines which provides for
"unbundling" or separating the various components of its services, i.e., supply,
storage, gathering, transportation and sales. A current issue related to Order
No. 636 is the regulation of natural gas gathering. Generally, natural gas
producers are concerned that the transfer of gathering facilities to non-
regulated entities will result in decreased competitiveness and accessibility to
markets. Neither the FERC nor the courts have resolved this matter, and, at this
time, the Company is unable to determine the effect that this matter may have on
its operations.
The Company may conduct operations on federal oil and natural gas leases, and
such operations must comply with numerous regulatory restrictions and
requirements issued by the Mineral Management Service, including various
nondiscrimination statutes, and certain of such operations must be conducted
pursuant to appropriate permits issued by the Bureau of Land Management.
Employees
As of December 31, 1994, the Company employed 13 persons, none of whom are
represented by a labor union or collective bargaining agent. Also at December
31, 1994, the Company had engaged five persons on a temporary contract basis to
perform certain financial and administrative functions. The Company considers
its relations with its employees to be good and has experienced no work
stoppages associated with labor disputes or grievances.
13
<PAGE>
ITEM 2. PROPERTIES
Information.
For information concerning the Company's properties, see "Item 1. Business -
Business Segment
ITEM 3. LEGAL PROCEEDINGS
Reorganization Proceeding
For information concerning the Company's Reorganization Proceeding, see
"Item 1. Business-Reorganization Proceeding".
NFG Litigation
For information concerning the NFG Litigation, see "Item 1. Business-NFG
Litigation".
New York Department of Environmental Conservation
In January 1990, the New York State Department of Environmental Conservation,
Division of Mineral Resources ("DEC") notified TGX that it considered TGX to be
in violation of certain provisions of the environmental and conservation laws of
the State of New York concerning approximately 150 natural gas wells and
production facilities located in Chautauqua and Erie Counties. To settle this
dispute, TGX entered into a consent order (the "Agreed Order") providing that
TGX will (a) furnish status reports that will disclose the production history
for certain wells, (b) install dehydration equipment on certain wells, and (c)
submit to the DEC (i) a schedule identifying certain wells to be serviced, (ii)
a "Plugging and Abandonment Program" for certain wells, and (iii)) a testing and
reporting schedule for certain wells. The Agreed Order imposed a civil penalty
on TGX in the amount of $139,000, which was suspended permanently as a result of
TGX complying with the terms of the Agreed Order. TGX has completed operations
on all wells subject to the Agreed Order. Pursuant to the DEC's requirements,
TGX provided a letter of credit from BMO in the amount of $300,000 which was to
be utilized by the DEC if TGX did not comply with the Agreed Order. Such letter
of credit was collateralized with the Company's cash, held by BMO. In May 1994,
the DEC agreed to reduce the letter of credit amount to $150,000 and a like
amount of cash collateral was released. In February 1995, the letter of credit
was completely eliminated and the remaining cash collateral released by BMO.
Litigation Against Former Officers and Directors
TGX is currently involved in litigation against certain former officers and
directors. See "Item 13. Certain Relationships and Related Transactions -Paragon
Resources, lnc."
Other
In August 1992, certain unleased mineral interest owners commenced a legal
action against TGX, as operator of certain wells, in the 19th Judicial District
Court for East Baton Rouge Parish, Louisiana (Case Number 383844, Division "A").
The complaint alleges that revenues in excess of the reasonable costs of
drilling, completing, and operating certain wells have not been credited to the
interests of the unleased mineral interest owners. This case is in the discovery
stage and if settlement negotiations are not successful, TGX will vigorously
defend itself in the litigation.
In March 1994, a hearing was conducted in the Bankruptcy Court regarding the
final allowance of pre-petition and administrative claims related to an
overriding royalty interest previously conveyed by TGX. As a result of this
hearing, the Bankruptcy Court established the method for computing these claim
amounts. The parties stipulated that the finally allowed pre-petition claim
amount was $600,000 which has been satisfied with the issuance of Senior
Preferred. Previously, the Company had estimated this claim amount and therefore
it had been included in the financial statements for prior years. Pursuant to
the Bankruptcy Court's order, certain post-petition but prior to October 2, 1992
claims are to be treated as administrative claims. The administrative claim
amount will be calculated by the claimant, subject to review and approval by the
Company, and pursuant to the terms of the Plan. Any claims subsequent to October
2,1992 are subject to the Bankruptcy Court's review, including ownership of the
overriding royalty interest.
14
<PAGE>
From time to time, in the normal course of business, the Company is a party to
various other litigation matters the outcome of which, to the extent not
otherwise provided for, should not have a material adverse effect on the
Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
During the fourth quarter of 1994, no matters were submitted to a vote of the
security holders.
15
<PAGE>
PART II.
ITEM 5. MARKET FOR THE REGISTRANTS SECURITIES AND RELATED STOCKHOLDER MATTERS
As a result of TGX's Chapter 11 filing, in March 1991, the National
Association of Securities Dealers, Inc. (the "NASD") notified TGX that it was
terminating the inclusion of TGX's Common Stock on the Nasdaq National Market
System. Through June 1992, the Company's common stock price continued to be
reported on Nasdaq. Since July 1, 1992, TGX's Common Stock is not and the Senior
Preferred will not be included on the Nasdaq National Market System. TGX's
Common Stock is traded through the NASD's "bulletin board".
As of March 1,1995, there were approximately 4,000 holders of record of the
Company's Common Stock. The Senior Preferred will be issued to approximately 950
parties. For the period through June 30, 1992, the following table presents the
high and low bid prices for the Common Stock as reported by Nasdaq. For the
periods ending subsequent to June 30, 1992, the following table sets forth bid
prices reported by the National Quotations Bureau, Inc. All quotations represent
bid prices between dealers without retail markup or markdown or commission and
do not reflect actual transactions.
Quarter Ended High Low
------------- ---- ---
1994:
-----
March 31 $.001 $.001
June 30 .001 .001
September 30 .001 .001
December 31 .01 .001
1993:
-----
March 31 $.001 $.001
June 30 .001 .001
September 30 .001 .001
December 31 .001 .001
1992:
-----
March 31 $.063 $.063
June 30 .063 .063
September 30 .015 .001
December 31 .001 .001
Holders of Senior Preferred have a dividend and liquidation preference over
holders of other classes of Preferred Stock or the Common Stockholders. As of
December 31, 1994, the redemption value and accrued dividends related to the
Senior Preferred were $87,282,000 and $26,454,000, respectively. The Senior
Preferred dividends must be paid in full prior to paying any dividends for the
Common Stock. Under a liquidation scenario, after secured debt and other
liabilities have been paid or provided for, the Senior Preferred redemption
value of $87,282,000 plus any accrued dividends must be paid in full before any
liquidating distributions are made to the holders of other Preferred or Common
Stock.
The Company has not paid, and for the near future, does not anticipate paying,
any cash dividends to its Preferred or Common Stockholders. The Company is
prohibited from paying dividends on its Common Stock at any time that it is in
arrears in paying dividends on any class of its preferred stock. The Company is
currently in arrears in making such payments. For information concerning the
rights of preferred and common stockholders regarding dividends see "Item 1.
Business-Terms of Preferred and Common Stock..
On March 28,1995, the closing price per share of the Common Stock, as reported
by the National Quotations Bureau, Inc., was $.001.
The Senior Preferred has not been publicly traded, and therefore, the Company
cannot determine the market value, if any, therefor.
16
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data should be read in conjunction with
"Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations" and the Company's consolidated financial statements and the
related notes thereto appearing elsewhere herein.
<TABLE>
<CAPTION>
Reorganized Company/1/ Predecessor Company/1/
------------------------------------------------- ------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
(Restated) October 2, January 1,
Year Ended Year Ended through through Year Ended Year Ended
December 31, December 31, December 31, October 1, December 31, December 31,
(Thousands, except per share data) 1994 (4) 1993 1992 1992 1991 1990
- ------------------------------------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS:
From continuing oil and natural
gas operations:
Revenues $ 6,477 $ 10,997 $ 2,993 $ 9,830 $ 8,997 $ 15,706
Gross profit 1,614 5,795 1,638 3,536 4,885 7,565
Net (loss) applicable to
common stock (15,476) (26,951) (3,184) (4,916) (132,399) (11,107)
Per common share (.61) (1.06) (.13) (.19) (5.23) (.44)
Income (loss) from
discontinued operations - - - - (4,718)/2/ 265
Per common share - - - - (.19) .01
Capital expenditures 27 394 79 154 2,648 751
Average common shares
outstanding 25,314 25,314 25,314 25,314 25,314 25,314
FINANCIAL POSITION AT
END OF PERIOD
Working capital (deficit)/3/ $ (1,319) $ (9,209) $ (24,047) $ (4,503) $ (2,533) $ 8,096
Property and equipment, net 7,257 9,404 39,070 42,815 48,751 151,679
Net assets of discontinued
operation - - - - - 5,088
Total assets 10,676 30,065 45,129 51,657 56,026 174,837
Liabilities subject to
compromise - - - - 88,098 72,650
Long-term debt 6,020 - - 21,958 - -
Stockholders' equity (deficit) (43,711) (28,505) (1,824) (69,650) (65,437) 71,680
COMMON STOCK:
Shares outstanding at end of
period 25,314 25,314 25,314 25,314 25,314 25,314
Cash dividends paid - - - - - -
</TABLE>
___________________________
/1/ As used herein, "Predecessor Company" means the operations of the Company
prior to October 2, 1992, the effective date of the order regarding
substantial consummation of the Plan, and "Reorganized Company" means the
operations of the Company subsequent to that date. The effects of the
Reorganization Proceeding were accounted for in accordance with the fresh
start reporting standards promulgated under SOP 90-7. See "Item 1. The
Company-Fresh Start Reporting" and Note 2 of the Notes to the Consolidated
Financial Statements included elsewhere herein.
/2/ Includes $4,144 attributable to Loss on Sale on Discontinued Operations.
/3/ Excludes pre-petition liabilities as of December 31, 1991 and 1990.
/4/ Period results restated as discussed in Note 15 of the Notes to the
Consolidated Financial Statements included elsewhere herein.
17
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
As a result of the Reorganization Proceeding, which was substantially
consummated on October 2, 1992, the Company is required to present its financial
statements pursuant to fresh start reporting standards, and accordingly, the
financial statements of the Reorganized Company are not comparable to the
financial statements of the Predecessor Company. However, in the case of the
consolidated statement of operations, the Company believes that comments
comparing calendar years are appropriate in order to provide a more meaningful
understanding of the Company's operations.
The following discussion provides information which management believes is
relevant to an understanding and assessment of the Company's results of
operations, financial condition, and those presently known events, trends or
uncertainties that are reasonably likely to have a material impact on the
Company's future results of operations or financial condition or that are
reasonably likely to cause the historical financial statements not to be
necessarily indicative of future operating results or financial condition. It
should be read in conjunction with the selected financial data appearing in the
preceding section and the consolidated financial statements and related notes
appearing elsewhere herein.
Amounts in this discussion and analysis have been restated as disclosed in
Note 15 of the Notes to Consolidated Financial Statements.
RESULTS OF OPERATIONS
1994 Compared to 1993
A comparison of significant operating income components is (amounts in
thousands):
1994 1993 Change
---- ---- ------
Oil and natural gas sales $ 4,802 $ 9,730 (51%)
Gas gathering and treating revenues 727 938 (22%)
Gain on property sales, net,
and other revenues 948 329 189%
Operating expenses (3,188) (3,935) (19%)
Depletion, depreciation
and amortization (1,414) (2,995) (53%)
General and administrative expenses (2,239) (3,323) (33%)
------- -------
Operating income (loss) $ (364) $ 744 (149%)
======= =======
Revenues
Consolidated revenues for 1994 decreased 41% or $4,520,000 to $6,477,000 from
$10,997,000 for 1993. This decrease was related to property sales and production
loss related to the Starkey No.1 well. The decrease in revenues was partially
offset by significant gas balancing revenues recorded in 1994. Excluding the
gain on property sales and other revenues, which represent primarily
nonrecurring items, consolidated revenues decreased $5,139,000 or 48% to
$5,529,000 as compared to $10,668,000 for 1993.
Oil and natural gas production revenues for 1994 decreased by 51% or
$4,928,000. This decrease was primarily due to lower production volumes
resulting from property sales. The contribution to 1993 revenues from the New
York and Ohio properties sold was approximately $4,655,000. Oil and natural gas
revenues for 1994 were also impacted by average product price declines for both
oil and gas. The production decline impact on revenues was partially reduced by
gross gas balancing revenues of $809,000 received during 1994. The Company
records gas revenues on the net sales method and thus revenues are recorded when
received as opposed to the entitlement method.
18
<PAGE>
The gas balancing payments received represented sales, net to the Company, of
590,000 Mcf. A summary of the components of the revenue decrease, including gas
balancing and properties sold revenues, is (in thousands):
Production
Total Volume Price
----- ---------- -----
Oil $ (542) $ (426) $ (116)
Natural gas (4,386) (3,300) (1,086)
------- ---------- --------
$(4,928) $ (3,726) $ (1,202)
======= ========== ========
A summary of oil and natural gas sales volume and revenues for the respective
years is:
Summary of Oil Volume and Revenues
----------------------------------
1994 1993 Change
- --------------------------------------------------------------------------------
Oil revenues (in thousands) $ 940 $ 1,482 (37%)
Oil sales volume (barrels) 62,000 87,000 (29%)
Oil average price per barrel 15.16 $ 17.03 (11%)
- --------------------------------------------------------------------------------
Summary of Natural Gas Sales Volume and Revenues
------------------------------------------------
1994 1993 Change
- --------------------------------------------------------------------------------
Natural gas revenues (in
thousands) 3,862 $ 8,248 (53%)
Natural gas sales volume
(Bcf) 2.241 3.712 (40%)
Natural gas average sales
price per Mcf 1.72 $ 2.22 (23%)
- --------------------------------------------------------------------------------
In early 1994 the Company, in two unrelated sales, sold all of its New York
and Ohio oil and natural gas properties and related assets. As a result of the
BBC sale being effective December 1, 1993 and the later sale begins effective
March 1,1994, the 1994 operating results contained only limited financial
activity related to these sold properties as compared to 1993. The following
summary details the oil and natural gas production activity and related
financial results included in 1993 results for these sold properties (dollars in
thousands):
Oil sale volume (MBBLS) 5
Gas sale volume (BCF) 1.912
Oil and natural gas revenue $ 4,655
Operating expenses 2,130
--------
Net revenue $ 2,525
========
On an equivalent unit basis (one barrel of oil equals six MCF of natural gas
on a heating value basis), natural gas for 1994 represents 86% of the Company's
oil and natural gas sales volume and 80% of total oil and natural gas revenues.
Based on the January 1,1995 independent reserve report, gas production will
continue to be the dominant product and will represent approximately 75% of the
Company's future oil and natural gas production volumes on an equivalent unit
basis.
Natural gas gathering and treating revenues decreased by 22% or $211,000 to
$727,000 in 1994 as compared to $938,000 in 1993. This decrease is primarily
attributable to decreased volume throughput due to the Starkey No. 1 well going
off production in December 1993. Efforts to return the Starkey to production to
date have not been successful.
During 1994, the Company sold partnership producing properties and undeveloped
properties for a total of $2,174,000. This compares to 1993's sale of 164
producing wells for $441,000 which resulted in a net gain of
19
<PAGE>
$58,000. The producing properties sold in 1994, for $1,424,000, represented the
Company's interest in approximately 31 gross wells from liquidated partnerships,
resulting in a net gain of $766,000. This sale was primarily the result of the
Company's continuing effort to liquidate various private and public partnerships
for which it was managing general partner and certain non-strategic assets. The
undeveloped property sale represented acreage in the New York area and was sold
to BBC, the primary purchaser of the Company's New York assets, for $750,000
which represented net book value.
Costs and Expenses
Consolidated costs and expenses decreased by $16,907,000 or 68% to $8,007,000
for 1994 as compared to $24,914,000 for 1993. Included in 1993 costs and
expenses is a non-cash charge of $12,415,000 for a provision for loss on sale of
assets which represents the net book value of the Sold Properties, plus
transaction costs, in excess of the net consideration received. Excluding the
1993 charge for loss on sale of assets, consolidated costs and expenses for 1994
decreased by $4,492,000 or 36%.
For 1994, operating expenses decreased $747,000 or 19% to $3,188,000 as
compared to $3,935,000 for 1993. Operating expenses for 1994 and 1993 were 66%
and 40%, respectively, of oil and natural gas revenues and were $1.22 and $.93
on an equivalent Mcf basis, respectively. The higher rate per equivalent Mcf for
the current year is partially attributable to the Company's remaining properties
being of a mature nature thus resulting in lower production rates and higher
costs as certain operating costs are fixed and do not vary with production rates
or product price. Also included in 1994 is $583,000 of workover costs. Workover
costs for 1994 consisted primarily of $416,000 of costs related to the
unsuccessful attempts to return the Starkey No. 1 located in Comite Field, East
Baton Rouge Parish to production. Exclusion of the Starkey workover costs would
have reduced operating expenses as a percent of oil and natural gas revenues to
58% and cost per equivalent Mcf to $1.06. The overall decrease in current year
operating expenses is primarily the result of Sold Property expenses of
$2,130,000 being included in 1993 activity, reduced by 1994 increases for
nonrecurring costs. Operating expenses in 1994 also included $174,000 of
transportation costs related to the $809,000 of gas balancing revenues recorded
during the year and the reclassification of approximately $260,000 of net
general and umbrella liability costs. Operating expenses during 1993 also
included certain nonrecurring costs aggregating approximately $419,000. These
1993 costs were attributable to operation enhancement activities and unscheduled
maintenance costs ($94,000), increased natural gas treating, gathering and
compression cost ($80,000), producing well overhead rates and well control
insurance adjustments ($47,000), abandonment costs ($56,000), and operating
expenses related to the Amarex Partnerships ($142,000).
Depreciation, depletion and amortization ("DD&A") decreased by $1,581,000 or
53% due to lower sales volumes and a lower weighted average DD&A rate. In 1994,
management determined that as a result of the Company's improving financial
condition, including expected cash flow for 1995 and beyond, it could fund
development of its oil and gas reserves which had previously not been classified
as proved undeveloped. Accordingly, in 1994 the Company treated these reserves
as proved undeveloped for purposes of accounting estimates and financial
statement disclosures. As a result of utilizing total proved reserves in the
calculation, DD&A expense for 1994 was reduced by $847,000. The weighted average
DD&A rate for 1994 on an equivalent Mcf basis was $ .50 as compared to 1993's
rate of $ .78.
General and administrative expenses in 1994 decreased $1,084,000 or 33% to
$2,239,000 from $3,323,000 in 1993. This decrease was primarily the result of
staff reductions and the outsourcing of certain financial and administrative
functions and accounts receivable recoveries. In 1994 the Company liquidated
various partnerships for which it was managing general partner. Certain of these
partnerships owed the Company note and receivable amounts which had been fully
allowed for as a doubtful account in prior years. As a result of the partnership
property sales and other collection efforts, the Company recorded approximately
$751,000 of net accounts receivable recoveries as a reduction to general and
administrative expense. Administrative costs in 1994 were further decreased by
approximately $336,000 of gross insurance costs that were reallocated from
administrative costs to operating expenses. This insurance allocation results in
the better matching of costs to operations and allowed the Company to recoup a
portion of these costs from third parties who benefitted from such coverages on
operated and partnership properties. Also, included in 1994 expenses is $492,000
of nondeferable debt restructuring costs related to the BMO debt restructuring.
Included in 1993 are office relocations costs of approximately $225,000 and
certain legal fees of $350,000.
Interest expense decreased $1,080,000 or 48% in 1994 to $1,166,000 from
$2,246,000 in 1993. This decrease is primarily attributable to lower average
debt outstanding and lower interest rates. Total secured debt
20
<PAGE>
and note payments for 1994 totaled $16,301,000. The interest rate under the Bank
One facility is the bank's base rate plus 2% which resulted in a weighted
average effective rate of approximately 9.74% during 1994. The BMO debt
agreement minimum interest rate was 13%, but in conjunction with debt
restructuring on July 13, 1994, the interest rate was lowered to 10% on the
remaining debt.
Due to tax loss carry forwards, the Company currently pays federal and state
alternative minimum income taxes only. The 1994 tax provision of $17,000 was
primarily due to state taxes.
The extraordinary gain in 1994 of $831,000 was derived from the settlement, on
discounted basis, of certain Administrative Notes.
1993 Compared to 1992
A comparison of operating income is (amounts in thousands):
1993 1992 Change
-------- -------- --------
Oil and natural gas production $ 9,730 $ 9,142 6%
Natural gas gathering and treating 938 848 11%
Gain on property sales, net and other revenue 329 2,833 (88%)
Operating expenses (3,935) (3,968) (1%)
Depletion, depreciation and amortization (2,995) (2,800) 7%
General and administrative expenses (3,323) (3,592) (7%)
------- -------
Operating income $ 744 $ 2,463 (70%)
======= =======
Revenues
Consolidated revenues for 1993 decreased 14% to $10,997,000 compared to
$12,823,000 for 1992. Consolidated revenues for 1992 included $2,940,000 related
to the partial settlement agreement proceeds received from NFG. Excluding gain
on net property sales and other revenues from both periods, which is primarily
related to the partial settlement agreement proceeds and nonrecurring items,
consolidated revenues for 1993 increased 7% or $678,000 to $10,668,000 as
compared to $9,990,000 for 1992.
Oil and natural gas production revenues for 1993 increased by $588,000 to
$9,730,000 compared to $9,142,000 for 1992. Oil and natural gas production
revenue increased due to the recognition of greater production volumes and
higher average natural gas prices which were partially offset with lower average
oil prices. A summary of the components of this increase is (in thousands of
dollars):
Production
Total Volume Price
----- ---------- -----
Oil $ (102) $ 98 $ (200)
Natural gas 690 356 334
------- ------ -------
$ 588 $ 454 $ 134
======= ====== =======
A summary of oil and natural gas production and revenues for the respective
years is:
Summary of Oil Sales Volume Production and Revenues
---------------------------------------------------
1993 1992 Change
- --------------------------------------------------------------------------------
Oil revenues (in thousands) $ 1,482 $ 1,591 (7%)
Oil sales volume (barrels) 87,000 82,000 6%
Oil average price per barrel $ 17.03 $ 19.40 (12%)
- --------------------------------------------------------------------------------
21
<PAGE>
Summary of Natural Gas Sales Volume and Revenues
------------------------------------------------
1993 1992 Change
- --------------------------------------------------------------------------------
Natural gas revenues (in thousands) $ 8,248 $ 7,551 9%
Natural gas sales volume (Bcf) 3.712 3.545 5%
Natural gas average sales price per Mcf $ 2.22 $ 2.13 4%
- --------------------------------------------------------------------------------
On an equivalent unit basis (one barrel of oil equals six Mcf of natural gas
on a heating value basis), natural gas for 1993 represents 88% of the Company's
oil and natural gas sales volumes and 85% of oil and natural gas revenues. Based
on the December 31, 1993 estimates of the Company's oil and natural gas
reserves, which excludes the Sold Properties, natural gas will represent
approximately 80% of the Company's future oil and natural gas sales volumes on
an equivalent unit basis.
A major factor affecting 1993 natural gas sales volumes was the decrease in
natural gas deliveries during the three month period May through July 1993 of
approximately 88,000 Mcf due to pipeline compressor repairs. Also in 1993, the
Company sold its interest in 164 wells for $441,000. These wells had a net book
value of $383,000 and the $58,000 gain related to the sale of these wells is
included in other revenue. The net reserve quantities attributable to these
wells were 27,500 barrels of oil and 526,000 Mcf of natural gas.
The expected decrease in sales volumes related to the sale of the wells and
the normal production decline was offset by improved production techniques and
the current recognition of beneficial interests in the operating income of
certain Amarex Partnerships. In conjunction with the consummation of plans of
reorganization for certain Amarex Partnerships, in December 1985, the Company
advanced approximately $2,445,000 on behalf of those Amarex Partnerships. The
repayment of these advances was subordinated to the payment in full by the
Amarex Partnerships of a production payment issued in satisfaction of certain
claims. Due to the uncertainty related to the collection of the advances, the
Company did not record them as assets at the time they were made. In September
1993, the production payment was paid in full and the Company began receiving
repayment of the advances from the Amarex Partnerships which will be recorded as
beneficial interest in the operating income of the Amarex Partnerships. A
summary of the net operating income that was recognized in 1993 is (amounts in
thousands):
Oil sales volume (Mbbls) 4.3
Gas sales volume (Mmcf) 270
Oil and natural gas sales $ 611
Other revenue 67
Operating expenses (142)
General and administrative expenses (16)
-----
Operating income $ 520
=====
The price that the Company receives for its oil and natural gas production
depends on many variables over which it has little or no control. Average
natural gas prices for 1993 were higher than recent prior periods due to
numerous factors including, but not limited to, (i) lower than expected natural
gas storage levels, (ii) anticipation of pipeline restructuring filing under the
FERC Order 636, (iii) the revision of natural gas production proration rules in
Oklahoma and Texas, and (iv) reduced competition resulting from declining
deliverability of existing United States wells. Due to the current imbalance
between supply and demand, 1993 oil prices have decreased compared to 1992. The
Company is unable to predict the extent or duration of the current trend for oil
and natural gas prices.
During 1993, the weighted average price paid for natural gas under the NFG
Contract was $2.26 per MCF compared to $2.72 per MCF in 1992. NFG notified TGX
that for a six month period commencing May 1993, it would accept delivery of
fifty percent (50%) of TGX's production for natural gas dedicated under the
Contract and would pay for such deliveries based on the a price equal to the
average long-term contract price between NFG and other
22
<PAGE>
natural gas producers ("NFG L-T Price"). NFG also notified TGX that any
deliveries to it in excess of this specified quantity ("Excess Gas") would be
paid for at a price equal to NFG's spot price for similar production and that
NFG might discontinue or limit deliveries of Excess Gas. For the period from May
through October 1993, the average price paid by NFG was $2.24 which was less
than TGX's average spot price for the sale of other natural gas production in
the area. The Company is litigating various provisions, including the price to
be paid, of the NFG Contract. See "Item 1. NFG Litigation".
Natural gas gathering and treating revenues increased 11% to $938,000 in 1993
compared to $848,000 in 1992. This increase is primarily attributable to
increased volume throughput and higher treating fees which had been reduced in
early 1992 due to low natural gas prices.
Costs and Expenses
Consolidated costs and expenses increased by $10,572,000 or 74% to $24,914,000
for 1993 compared to $14,342,000 for 1992. Included in 1993 costs and expenses
is a non-cash charge of $12,415,000 for a provision for loss on sale of assets
which represents the net book value of the Sold Properties, plus transaction
costs, in excess of the net consideration received. Excluding the 1993 charge
for loss on sale of assets and the 1992 full cost ceiling adjustment of
$1,505,000 and reorganization expense credit of $400,000, consolidated costs and
expenses for 1993 decreased 6% or $738,000 to $12,499,000 as compared to
$13,237,000 for 1992.
For 1993, operating expenses decreased $33,000 or 1% to $3,935,000 compared to
$3,968,000 for 1992. Operating expenses for 1993 and 1992 were 40% and 43%
respectively of oil and natural gas revenues and were $.93 and $.98 on an
equivalent MCF basis, respectively. Operating expenses during 1993 include costs
aggregating $419,000 attributable to (i) operations related to the Company's oil
and natural gas properties in Arkansas and New York that were conducted to
enhance or maintain oil and natural gas production volumes ($55,000) (ii)
unplanned compressor and meter repairs in New York ($39,000), (iii) increased
natural gas treating, gathering and compression costs rates for properties
located in Arkansas and Louisiana due to increased production ($80,000), (iv)
adjustments related to producing well overhead rates and well control insurance
($47,000), (v) the abandonment of certain wells ($56,000), and (vi) operating
expenses related to the Amarex Partnerships ($142,000). Certain operating
expenses are fixed and accordingly will not vary with increases or decreases in
oil and natural gas production.
Effective October 2, 1992, the Company adopted the successful efforts
accounting method for oil and natural gas operating activities. Depletion,
depreciation, and amortization increased by 7% or $195,000 to $2,995,000 in 1993
from $2,800,000 in 1992 primarily due to a higher per unit depletion and
depreciation rates for oil and natural gas computed on a field basis under
successful efforts accounting. For 1993, the aggregate depletion and
depreciation rate for oil and natural gas properties was $.78 per equivalent MCF
and based on current information, it is estimated that this rate for 1994 will
be $.90 per equivalent MCF. The depletion and depreciation rate could be
materially affected by various events including but not limited to (i) the
ability of the Company to conduct oil and natural gas operations and (ii)
consistent rates of production from each field throughout the year.
General and administrative expenses in 1993 decreased $269,000 or 7% to
$3,323,000 form $3,592,000 in 1992. In order to reduce costs and improve
efficiency, the Company consolidated its operations and administrative offices
during 1993 and approximately $225,000 for relocation and transition costs
related to this consolidation is included in 1993 general and administrative
expenses. Also, 1993 general and administrative expense includes $100,000 for
the amortization of deferred executive compensation which is a charge that was
not incurred in 1992.
Interest expense decreased $631,000 or 22% in 1993 to $2,246,000 from
$2,877,000 in 1992 which included $333,000 related to the amortization of debt
issuance costs. This decrease is primarily attributable to the Company's
weighted average secured indebtedness for 1993 decreasing to $23,086,000
compared to $26,097,000 for 1992. The weighted average interest rate on secured
debt in 1993 and 1992, excluding amortization of debt issuance costs, was 9.93%
and 9.75%, respectively. In January 1994, the Company repaid approximately $14.3
million of its outstanding bank debt and it expects to reduce its bank debt to
approximately $3.75 million as a result of its financial restructuring. The
interest rate for the restructured bank debt will be the bank's base rate plus
2% (approximately 8.75%).
In 1992, reorganization expense included $235,000 related to the accrual of
post-petition contractual interest through January 21, 1992, the Effective Date
of the Plan. In 1992, the Bankruptcy Court set finally allowed amounts for
certain claims that were less than the amounts accrued by the Company. As a
result, the Company adjusted the accruals to actual and realized a benefit of
$1,335,000 which was offset by $700,000 for professional fees related
23
<PAGE>
to (i) the objection to certain administrative claims related to the
Reorganization Proceeding and (ii) the consummation of the Plan, as modified.
Subsequent to the Effective Date, the Company has no obligation for contractual
interest related to unsecured finally allowed claims. Since the Plan has been
consummated, the Company no longer incurs reorganization expenses.
FINANCIAL CONDITION
In 1994, the Company's capital expenditures were not significant. However,
property additions of $381,000 were recorded representing properties received
from certain affiliated partnerships in satisfaction of notes and receivables.
The Company also incurred workover costs of $583,000. In 1995, the Company
anticipates increasing its capital and workover expenditures through the
development of existing proved undeveloped and developed non-producing reserves,
drilling or acquisition.
At December 31, 1994, the Company's working capital deficit was $1,319,000
which included $203,000 of principal and interest due on the Administrative
Notes and $934,000 related to various pre-petition obligations.
The July 13, 1994 debt restructuring with BMO and establishment of a new line
of credit with Bank One significantly improved the Company's financial condition
while curing the BMO Events of Default. The Bank One credit facility's
borrowings outstanding as of December 31, 1994 totaled $1,150,000 with a
borrowing base of $2,070,000 which is reduced monthly by $56,000. Due to the
excess of borrowing base over year end borrowing and the current monthly
facility reduction rate, no current maturities are reflected. The borrowing base
is redetermined on a semi-annual basis or at any time at Bank One's election.
The next scheduled redetermination date is May 1, 1995. The Bank One credit
facility is secured by substantially all of the Company's assets and incudes
financial and default covenants standard in the industry. Pursuant to the terms
of the Bank One credit agreement, the Company is required to maintain certain
financial ratios including a current ratio of 1.2 to 1 after excluding certain
liabilities and making other adjustments as allowed under the facility. After
making such current ratio adjustments, the Company at December 31, 1994 was in
compliance with the current ratio and other financial ratios and covenants.
Though the Company has complied with all covenant requirements to date, there
can be no assurance that it will be able to continue such compliance or that its
borrowing base may not be significantly reduced during future redeterminations
which could result in required principal reductions during 1995. At December 31,
1994, the non-recourse BMOF debt totaled $4,870,000, including total accrued
interest of $218,000. The BMOF note is payable from NFG Litigation proceeds,
if any, and all related interest is payable in kind through the issuance of
additional notes until December 31, 1997, or for such further time as BMOF
elects to extend maturity of such note.
The Senior Preferred has a liquidation preference value of $10 per share and
is redeemable in whole or in part at the option of the Company at any time at a
price per share equal to the liquidation preference amount per share plus all
accrued and unpaid dividends to the date of redemption. Subject to Delaware law,
the Company must redeem all outstanding shares of Senior Preferred on or before
January 21, 2002. The Senior Preferred is entitled to receive cumulative,
compounded 10% annual dividends payable quarterly. Payment of the dividends on
the Senior Preferred is mandatory if sufficient surplus funds (after reasonable
reserves for capital budget items and working capital reserves) are legally
available for such purpose. Until the Senior Preferred is fully redeemed, the
Junior and Old Preferred Stock receive dividends payable in additional shares of
Junior or Old Preferred Stock. For financial reporting purposes, the Senior
Preferred has both debt and equity characteristics. Accordingly, it is not
classified as a component of stockholders' equity. At December 31,1994, the
Senior Preferred redemption value and accrued dividends were $87,282,000 and
$26,454,000, respectively. This amount plus any additional accrued dividends
must be satisfied before any value can be attributed to the holders of Old
Preferred and Common Stock.
At December 31,1994, the Stockholders' deficit was $43,711,000. Due to the
dividend requirements for the Senior, Junior, and Old Preferred Stock and
accretion of the redemption value of Senior Preferred, under the current capital
structure, it is probable that the Company's Stockholders' equity will remain a
deficit for the foreseeable future.
LIQUIDITY AND CAPITAL RESOURCES
For 1994, the Company's cash provided by operating activities was $11,999,000.
The cash flow from operations was primarily due to 1994 property sales
receivable collection. Substantially all of 1994's operating cash flow was
dedicated to debt retirement.
24
<PAGE>
The July 13, 1994 debt restructuring with BMO and establishment of a new line
of credit with Bank One significantly improved the Company's liquidity while
curing the BMO Events of Default. Based on the December 31, 1994 borrowing base
of $2,070,000 and outstandings of $1,150,000, the Company had availability under
the facility of $920,000. Amounts borrowed under the line of credit are due July
1997.
In conjunction with applying the net proceeds related to the sale of assets to
BBC, BMO reserved $300,000 for a TGX contingent liability under a letter of
credit. In May 1994, the letter of credit amount was reduced by $150,000 and
this amount was applied toward BMO obligations. The remaining $150,000 letter of
credit was secured by cash and was released to the Company in February 1995.
In 1994, a majority of the limited partner interests in two partnerships voted
to appoint TGX as the liquidating trustee for the partnerships. As a result, TGX
solicited offers to sell the oil and natural gas properties of the partnerships
and subsequently accepted an offer to sell certain of the partnerships' oil and
natural gas properties for $2.67 million. TGX's share of the liquidating cash
distributions from the partnerships ($1.367 million) was applied toward BMO debt
obligations. During 1994, the Company continued a program of reviewing the
status of affiliated partnerships to determine whether or not the partnerships
should be liquidated. Due to the limited remaining asset value for most of these
partnerships and their ongoing administrative costs, substantially all of the
partnerships will be liquidated. The Company liquidated 17 partnerships in 1994
through sales or foreclosure pursuant to Company held partnership notes and
anticipates liquidating through sale the remaining eight public partnerships by
mid-1995. As a result of the 1994 partnership liquidations, the Company obtained
additional direct interests in related oil and natural gas properties having an
estimated value of $381,000 and realized the recoupment of $751,000 of
previously reserved receivables and notes. Liquidation of all remaining
partnerships in 1995 will eliminate general and administrative reimbursements
derived from such partnerships by the Company which should be offset by related
administrative cost savings.
Pursuant to the terms of various agreements, the Company, as a working
interest owner, is responsible for marketing its share of natural gas production
from certain properties. If the Company is unable or unwilling to market its
share of natural gas production from a property, its under-produced status is
subject to balancing with other working interest owners who have sold more than
their proportionate share of natural gas production. On an aggregate net basis
for certain natural gas properties, it appears that the Company is substantially
under-produced and is conducting negotiations to recoup or otherwise settle its
net under-produced status. The Company received approximately $634,000, net of
expenses, as a result of such negotiations during the fourth quarter of 1994.
The Company can give no assurance as to its ability to recoup or otherwise
settle any additional net under-produced wells in the immediate future.
In addition to the ongoing oil and gas production operations, a key factor in
the Company's future will be the final resolution of the litigation with NFG.
While the Company has attempted to commence settlement negotiations with NFG, to
date no meaningful discussions have taken place. If a settlement cannot be
reached, the Company intends to prosecute this litigation with every reasonable
resource available to it. The outcome of the NFG Litigation, which may be many
years away if a settlement cannot be reached, could materially affect the
Company's future. Under the restructured BMO credit agreement, BMO's subsidiary
will be entitled to receive the initial $4,652,000 of any settlement proceeds,
plus interest, and in certain instances, BMO, after the Company has received the
same initial amount paid to BMO, may be entitled to receive up to 50% of any
additional settlement proceeds. Based on the Company's calculation, the gross
price between the price actually paid by NFG and the price required by the New
York Federal Court's order (assuming a contract price of $4.41 per Mcf for
winter and $4.01 for summer) is approximately $23,912,000 as of December 31,
1994, including statutory interest.
During 1995, the Company will continue to review its investment opportunities,
consistent with its available capital, to determine if asset enhancement can be
obtained either through development of existing proved developed non-producing
reserves, drilling or acquisition. However, considering the Company's current
financial position and the inability to predict (i) the outcome of the NFG
Litigation and (ii) the success of any cost reductions, the Company cannot
currently determine if it will be able to successfully implement its business
plan and strategy.
INFLATION AND CHANGES IN PRICES
The Company's revenues have been and will continue to be affected by changes
in oil and natural gas prices which have been unstable. For management purposes,
the Company assumes that oil and natural gas prices will escalate at 5% per
annum and that costs and expenses will escalate at 4% per annum. The principal
effects of
25
<PAGE>
inflation on the Company relate to the costs required to drill, complete and
operate oil and natural gas properties. Such costs have also been on a general
downward trend since the early 1980's due primarily to the industry-wide
decrease in drilling activity and the Company's continuing efforts to monitor
and reduce operating expenses.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The Company's consolidated financial statements as of December 31, 1994 and
1993 and for each of the three years in the period ended December 31, 1994, and
the reports of Price Waterhouse LLP, independent accountants, follow.
26
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
POST-EMERGENCE CONSOLIDATED FINANCIAL STATEMENTS
To the Board of Directors and Stockholders of TGX Corporation
In our opinion, the accompanying consolidated financial statements listed in
the index appearing under Item 14(A)(1) and (2) on page 57 present fairly, in
all material respects, the financial position of TGX Corporation and its
subsidiaries (the Company) at December 31, 1994 and 1993, and the results of
their operations and their cash flows for the years ended December 31, 1994 and
1993 and for the period from October 2,1992 to December 31, 1992, in conformity
with generally accepted accounting principles. These financial statements are
the responsibility of the Company's management; our responsibility is to express
an opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
As discussed in Note 2 to the consolidated financial statements, on
January 21, 1992, the United States Bankruptcy Court for the Western District
Court confirmed the Company's Amended Plan of Reorganization (the Plan). The
Plan was substantially consummated on October 2, 1992, and the Company emerged
from bankruptcy. In connection with its emergence from bankruptcy, the Company
adopted fresh start reporting. As a result of the adoption of fresh start
reporting, the post-emergence consolidated financial statements are not
comparable to the pre-emergence consolidated financial statements.
The accompanying consolidated financial statements have been prepared assuming
that the Company will continue as a going concern. As discussed in Note 14 to
the consolidated financial statements, the Company has a substantial accumulated
deficit and has suffered recurring losses from operations, as well as cash flow
deficits that raise substantial doubt about its ability to continue as a going
concern. Management's plans in regard to these matters are also discussed in
Note 14. The consolidated financial statements do not include any adjustments
that might result from the outcome of this uncertainty.
As discussed in Notes 1 and 9 to the consolidated financial statements, on
October 2, 1992, the Company changed its methods of accounting for oil and
natural gas properties and income taxes.
As discussed in Note 15, the Company has restated its 1994 financial
statements to account for the Bank of Montreal ("BMO") debt conversion as a
troubled debt restructuring. The BMO debt conversion was originally accounted
for as an extinguishment of debt.
PRICE WATERHOUSE LLP
Houston, Texas
March 28, 1995 except as to
Note 15 which is as of
January 3, 1997
27
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
PRE-EMERGENCE CONSOLIDATED FINANCIAL STATEMENTS
To the Board of Directors and Stockholders of TGX Corporation
In our opinion, the accompanying consolidated financial statements listed in
the index appearing under Item 14(A)(1) and (2) on page 57 present fairly, in
all material respects, the results of operations and cash flows of TGX
Corporation and its subsidiaries (the Company) for the period from January 1,
1992 to October 1, 1992, in conformity with generally accepted accounting
principles. These financial statements are the responsibility of the Company's
management; our responsibility is to express an opinion on these financial
statements based on our audit. We conducted our audit of these statements in
accordance with generally accepted auditing standards which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for the opinion expressed
above.
As discussed in Note 2 to the consolidated financial statements, on
January 21, 1992, the United States Bankruptcy Court for the Western District
Court confirmed the Company's Amended Plan of Reorganization (the Plan).
The Plan was substantially consummated on October 2, 1992 and the Company
emerged from bankruptcy. In connection with its emergence from bankruptcy, the
Company adopted fresh start reporting. As a result of the adoption of fresh
start reporting, the post-emergence consolidated financial statements are not
comparable to the pre-emergence consolidated financial statements.
The accompanying consolidated financial statements have been prepared assuming
that the Company will continue as a going concern. As discussed in Note 14 to
the consolidated financial statements, the Company has substantial accumulated
deficit and has suffered recurring losses form operations, including a net loss
before extraordinary gain for debt forgiveness in the current year, as well as
cash flow deficits that raise substantial doubt about its ability to continue as
a going concern. Management's plans in regard to these matters are also
discussed in Note 14. the consolidated financial statements do not include any
adjustments that might result from the outcome of this uncertainty.
As discussed in Notes 1 and 9 to the consolidated financial statements, on
October 2, 1992, the Company changed its methods of accounting for oil and
natural gas properties and income taxes.
PRICE WATERHOUSE LLP
Houston, Texas
March 28, 1995
28
<PAGE>
TGX Corporation and Subsidiaries
CONSOLIDATED BALANCE SHEET
================================================================================
(Restated -
Note 15)
December 31,
------------------------
(Thousands, except for share data) 1994 1993
- --------------------------------------------------------------------------------
ASSETS
Current assets:
Cash and cash equivalents $ 676 $ 1,220
Accounts receivable, net of allowance
for doubtful accounts of
$373 and $763, respectively 1,206 1,698
Accounts receivable from affiliates, net -Note 10 504 1,154
Net oil and natural gas properties held for sale - 15,128
Other current assets 60 148
- --------------------------------------------------------------------------------
Total current assets 2,446 19,348
- --------------------------------------------------------------------------------
Property and equipment:
Oil and natural gas properties 10,407 11,434
Other property and equipment 157 442
Accumulated depletion, depreciation and amortization (3,307) (2,472)
- --------------------------------------------------------------------------------
Property and equipment, net 7,257 9,404
- --------------------------------------------------------------------------------
Accounts and notes receivable from affiliates,
net -Note 10 - 100
Investment in Comite Field Plant Venture -Note 5 878 1,015
Other assets 95 198
- --------------------------------------------------------------------------------
Total other assets 973 1,313
- --------------------------------------------------------------------------------
TOTAL ASSETS $ 10,676 $ 30,065
================================================================================
LIABILITIES AND STOCKHOLDERS' DEFICIT
Current liabilities:
Accounts payable and accrued liabilities -Note 6 $ 3, 352 $ 7,556
Accounts payable to affiliates 242 101
Current maturities of long-term debt -Note 3 - 19,499
Notes payable 171 1,401
- --------------------------------------------------------------------------------
Total current liabilities 3,765 28,557
- --------------------------------------------------------------------------------
Long-term debt -Note 3 6,020 -
- --------------------------------------------------------------------------------
Total liabilities 9,785 28,557
- --------------------------------------------------------------------------------
Commitments and contingencies -Note 4
Redeemable Senior Preferred Stock, 1,498,534 issued;
7,230,712 shares to be issued, redemption
value $87,292,000 -Note 7 44,602 30,013
- --------------------------------------------------------------------------------
Stockholders' deficit: -Note 8
9% Cumulative Convertible Preferred stock,
300,000 shares issued plus 131,000 and 104,000,
respectively, shares to be issued for dividends 431 404
Common stock, 28,976,791 shares issued;
25,313,533 outstanding 290 290
Additional paid-in capital 1,179 936
Accumulated deficit (45,611) (30,135)
- --------------------------------------------------------------------------------
Total stockholders' deficit (43,711) (28,505)
- --------------------------------------------------------------------------------
TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT $ 10,676 $ 30,065
================================================================================
See accompanying notes to consolidated financial statements
29
<PAGE>
TGX Corporation and Subsidiaries
CONSOLIDATED STATEMENT OF OPERATIONS
<TABLE>
<CAPTION>
Predecessor
Reorganized Company(1) Company(1)
------------------------------------- --------------------------
(Restated - Note 15) October 2, January 1,
Year Ended Year Ended through through
December 31, December 31, December 31, October 1,
(Thousands, except per share data) 1994 1993 1992 1992
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
REVENUES
Oil and natural gas production $ 4,802 9,730 $ 2,641 $ 6,501
Natural gas gathering 309 417 116 285
Share of earnings of natural gas
treating plant 418 521 201 246
Gain on property sales, net 766 58 - -
Other, net 182 271 35 2,798
- ------------------------------------------------------------------------------------------------------------------------------------
6,477 10,997 2,993 9,830
- ------------------------------------------------------------------------------------------------------------------------------------
COSTS AND EXPENSES
Operating expenses 3,188 3,935 1,003 2,965
Depletion, depreciation and amortization 1,414 2,995 916 1,884
Provision for loss on sale of assets - 12,415 - -
Full cost ceiling adjustment - - - 1,505
General and administrative expenses 2,239 3,323 712 2,880
Interest 1,166 2,246 612 2,265
Reorganization expenses, net of
post petition interest income - - - (400)
- ------------------------------------------------------------------------------------------------------------------------------------
8,007 24,914 3,243 11,099
- ------------------------------------------------------------------------------------------------------------------------------------
LOSS BEFORE INCOME TAXES AND
EXTRAORDINARY GAIN (1,530) (13,917) (250) (1,269)
Income tax expense - Note 9 17 - - -
- ------------------------------------------------------------------------------------------------------------------------------------
NET LOSS BEFORE EXTRAORDINARY
GAIN (1,547) (13,917) (250) (1,269)
Extraordinary gain -Note 3 831 - - -
- ------------------------------------------------------------------------------------------------------------------------------------
NET LOSS (716) (13,917) (250) (1,269)
Preferred stock dividends, net (10,780) (10,139) (2,305) (3,647)
Accretion of Senior Preferred
redemption value (3,980) (2,895) (629) -
- ------------------------------------------------------------------------------------------------------------------------------------
NET LOSS APPLICABLE TO
COMMON STOCK $ (15,476) $ (26,951) $ (3,184) $ (4,916)
====================================================================================================================================
PER SHARE OF COMMON STOCK AMOUNTS:
Before extraordinary gain $ (.64) $ (1.06) $ (.19) $ (.19)
Extraordinary gain .03 - -
- ------------------------------------------------------------------------------------------------------------------------------------
NET LOSS $ (.61) $ (1.06) $ (.13) $ (.19)
====================================================================================================================================
AVERAGE COMMON SHARES
OUTSTANDING 25,314 25,314 25,314 25,314
====================================================================================================================================
</TABLE>
(1) As used herein, "Predecessor Company" means the operations of the Company
prior to October 2, 1992, the effective date of the order regarding
substantial consummation of the Amended Plan of Reorganization, and
"Reorganized Company" means the operations of the Company subsequent to
that date.
See accompanying notes to consolidated financial statements
30
<PAGE>
TGX Corporation and Subsidiaries
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
Predecessor
Reorganized Company (1) Company (1)
----------------------------------- -----------------------------
(Restated - Note 15) October 2, January 1,
Year Ended Year Ended through through
December 31, December 31, December 31, October 1,
(Thousands, except per share data) 1994 1993 1992 1992
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Cash flows from operating activities:
Net loss $ (716) $ (13,917) $ (250) $ (1,269)
Adjustments to reconcile net loss
to cash provided by operating activities:
Depletion, depreciation and amortization 1,414 2,995 916 3,389
Amortization of debt issuance costs - - - 333
Provision for loss on sale of assets - 12,415 - -
Non-cash recovery of affiliate receivable (381) - - -
Recovery of accounts receivable loss provisions 751 - - -
Interest to be paid through the issuance of
additional notes 218 - - -
Extraordinary gain (831) - - -
Changes in operating assets an liabilities:
Decrease in accounts receivable 492 17 100 917
(Increase) decrease in accounts due from/to
affiliates, net 40 (531) (15) 781
(Increase) decrease in other current assets 15,128 222 (63) 126
Increase (decrease) in accounts payable
and accrued expenses (4,204) 2,337 389 (561)
Decrease in other assets 88 - - 232
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 11,999 3,538 1,077 3,948
- ------------------------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Capital expenditures (27) (394) (79) (154)
Disposal of assets, net 1,406 14 - 402
Consideration from disposition of Consummation
Collateral - - - 2,286
Decrease (increase) in other assets 74 383 18 (5)
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by
investing activities 1,453 3 (61) 2,529
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
See accompanying notes to consolidated financial statements
31
<PAGE>
TGX Corporation and Subsidiaries
CONSOLIDATED STATEMENT OF CASH FLOWS (Continued)
<TABLE>
<CAPTION>
Predecessor
Reorganized Company(1) Company(1)
------------------------------------- ----------------------------
(Restated - Note 15) October 2, January 1,
Year Ended Year Ended through through
December 31, December 31, December 31, October 1,
(Thousands, except per share data) 1994 1993 1992 1992
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Cash flows from operating activities:
Debt issuance costs - - - (1,250)
Principal payments of long-term debt and
notes payable (16,301) (3,799) (822) (4,041)
Payment of pre-petition liabilities and
administrative claims - - (635) (4,291)
Advances pursuant to Revolving Credit
Facility 1,975 90 - 550
Debt transaction costs and other 230 - - -
Decrease in affiliate accounts receivable 100 - - -
Proceeds related to term loans pursuant to
Amended Credit Agreement - - - 1,442
Notes payable issued to administrative claimants - 91 (24) 2,005
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash used by financing activities (13,996) (3,618) (1,481) (5,585)
- ------------------------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and
cash equivalents (544) (77) (465) 892
Cash and cash equivalents at beginning
of period 1,220 1,297 1,762 870
- ------------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 676 $ 1,220 $ 1,297 $ 1,762
====================================================================================================================================
Supplemental Disclosure of Non-Cash
Investing and Financing Activities:
Properties acquired through foreclosure
of affiliated partnerships $ 381 $ - $ - $ -
Forgiveness of notes payable 831 - - -
Interest to be paid through issuance
of additional notes 218 - - -
</TABLE>
See accompanying notes to consolidated financial statements
32
<PAGE>
TGX Corporation and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1994, 1993 and 1992
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Business and Reorganization Proceeding
TGX Corporation (''TGX") (collectively with its subsidiaries, the "Company"),
is a domestic independent energy company engaged in the production of oil and
natural gas. The Company is also engaged in intrastate natural gas gathering and
treating.
As discussed in Note 2, on February 22,1990, TGX filed a voluntary petition
for reorganization pursuant to Chapter 11 of the Bankruptcy Code. TGX's then
wholly owned subsidiaries, LEDCO, TGX Finance Corporation, Diablo Farms, Inc.,
and Templeton Energy Income Corporation, did not file petitions for
reorganization under the Bankruptcy Code nor did any of the limited or general
partnerships for which TGX serves as general partner. On January 7, 1992, the
Bankruptcy Court confirmed an Amended Plan of Reorganization (the "Plan") for
TGX and on October 2,1992 an order of substantial consummation regarding the
Plan became final and nonappealable. Accordingly, the Company implemented fresh
start reporting as of October 2, 1992.
The consolidated financial statements have been prepared on a going concern
basis, which contemplates continuity of operations and realization of assets and
liquidation of liabilities in the ordinary course of business.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of TGX
and its subsidiaries. All significant intercompany accounts and transactions
have been eliminated. The Company accounts for its investments in limited and
general partnerships under the proportionate consolidation method. Under this
method, the Company's financial statements include its pro-rata share of assets,
liabilities, revenues, and expenses of the limited and general partnerships in
which it owns beneficial interests. The Company's 35% investment in a natural
gas treating plant (Note 5) is accounted for using the equity method.
Oil and Natural Gas Properties
In conjunction with the implementation of fresh start reporting, as described
in Note 2, the Company also implemented the successful efforts method of
accounting for oil and natural gas operations. Under the successful efforts
method, capitalized cost relating to proved properties are amortized based on
proved reserves using the unit-of-production method. In 1994, management
determined that as a result of the Company's improving financial condition,
including expected cash flow for 1995 and beyond, that it could fund development
of its oil and gas reserves which had previously not been classified as proved
undeveloped. Accordingly, in 1994 the Company treated these reserves as proved
for purposes of accounting estimates and financial statement disclosure. As a
result of utilizing total proved reserves in the calculation, depletion,
depreciation and amortization for 1994 was reduced by $847,000. The cost of
unsuccessful exploration wells is charged to operations. If an assessment
indicates that an unproved property has been impaired, a loss is recognized by
providing a valuation allowance. Net capitalized costs in excess of future net
revenues, adjusted for tax effects, are charged to operations in the year during
which such excess occurs. Generally, a gain or loss is recognized on the
disposition of a property.
Prior to the implementation of fresh start reporting, the Company followed the
full-cost method of accounting for its oil and natural gas operations, and
accordingly, it capitalized all costs incurred in connection with the
acquisition, exploration and development of oil and natural gas properties,
whether productive or nonproductive. These capitalized costs comprised the full-
cost pool which was depreciated and depleted over the life of the estimated
proved reserves using the unit-of-production method. Any capitalized costs in
excess of the present value of proved oil and gas reserves were expensed in the
year in which such excess was determined.
The Company concluded that the successful efforts method was more appropriate
than the full-cost method since it would result in a better matching of oil and
natural gas revenues with the related exploration and production costs and
expenses.
33
<PAGE>
Other Property and Equipment
Depreciation of other property and equipment is provided on the straight-line
method over the estimated useful lives of the related assets, which range from 3
to 25 years.
Revenue Recognition
Revenue from the sale of crude oil is recognized upon the passage of title,
net of royalties. Revenue from natural gas production is recognized using the
sales method, net of royalties. Pursuant to the terms of various agreements, the
Company, as a working interest owner, is responsible for marketing its share of
natural gas production from certain properties. If the Company is unable or
unwilling to market its share of natural gas production from a property, its
under-produced status is subject to balancing with other working interest owners
who have sold more than their proportionate share of natural gas production. On
an aggregate net basis for certain natural gas properties, it appears that the
Company is in an under-produced status and is currently recouping or attempting
to settle its net under-produced status. Any balancing recoupments or
settlements, which will typically be over a period of time, are not anticipated
to be material to future operating results.
Cost and Expense Reimbursements
Pursuant to the provisions of the applicable agreements, the Company reduces
its general and administrative expenses by reimbursements for certain
administrative and operating costs paid or incurred in connection with the
administration and operation of oil and natural gas properties and limited and
general partnerships which are sponsored by the Company.
Income Taxes
In February 1992, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 109 -"Accounting for Income Taxes" which
requires an asset and liability approach for the financial accounting of income
taxes based on the differences that can occur between the tax bases of assets or
liabilities and their reported amounts in financial statements. In conjunction
with the implementation of fresh start reporting, the Company also adopted this
method of accounting for income taxes.
Per Share Amounts
Per share amounts are determined by dividing net income or loss applicable to
Common Stock by the weighted average number of common shares outstanding during
the year. In 1994, 1993 and 1992 the dilutive effect, if any, of the assumed
conversion of preferred stock to common stock was considered for the computation
of fully diluted income or loss per common share and such assumed conversion was
not material to the computation. The assumed exercise of outstanding stock
options was not included in the computation of per share amounts as their effect
was not dilutive.
Cash and Cash Equivalents
Cash includes cash on-hand and cash in interest-bearing accounts with original
maturities of 90 days or less.
Reclassifications
Certain amounts from prior years have been reclassified to conform to the
current year presentation.
2. REORGANIZATION PROCEEDING
On February 22, 1990, TGX filed a voluntary petition in the United
States Bankruptcy Court for the Western District of Louisiana, Shreveport
Division (the "Bankruptcy Court"), for reorganization pursuant to Chapter 11,
Title 11 of the United States Code (the "Reorganization Proceeding"). During the
balance of 1990, all of 1991 and a portion of 1992, TGX operated as debtor-in-
possession, continuing in possession of its estate and the operation of its
business and management of its property. On January 7, 1992, the Bankruptcy
Court confirmed an amended Plan of Reorganization ("Plan") for TGX, and the
confirmation order became effective on January 21,1992 (the "Effective Date").
On September 21,1992, the Bankruptcy Court determined that the Plan had been
substantially
34
<PAGE>
consummated, and the Bankruptcy Court's order of substantial consummation became
final and nonappealable on October 2, 1992.
As a result of the substantial consummation of the Plan and due to (i) the
reallocation of the voting rights of equity interests owners and (ii) the
reorganization value of TGX's assets being less than the total of all post-
petition liabilities and allowed claims at October 2, 1992, the effects of the
Reorganization Proceeding were accounted for in accordance with the fresh start
reporting standards promulgated under the American Institute of Certified Public
Accountants Statement of Position 90-7 "Financial Reporting by Entities in
Reorganization Under the Bankruptcy Code" ("SOP 90-7").
In conjunction with implementing fresh start reporting, a reorganization value
("RV") of the Company's assets and liabilities as of October 2, 1992 was
determined by management in the following manner:
The RV of proved oil and natural gas properties and other related
assets was determined based on future net revenues discounted to present
value utilizing a rate of 20%. For proved undeveloped properties, the RV
was determined to be 50% of discounted future net revenues. For the purpose
of calculating future net revenues of oil and natural gas properties, then
current oil and natural gas prices were escalated at five percent per annum
to certain maximum amounts and then current operating costs and expenses
were escalated at four percent per annum for the economic life of the
properties. The initial price for natural gas dedicated under the contract
(the "Contract") with National Fuel Gas Distribution Corporation ("NFG"),
which is currently a matter being litigated, was equal to 90% of the
rolling twelve month average price for No. 6 fuel oil in the Buffalo, New
York area (the "90% of No. 6 Fuel Oil Price"). The RV of oil and natural
gas properties also included $2,905,000 attributable to the difference,
plus interest, between the price that NFG paid since September 1984 and the
90% of No. 6 Fuel Oil Price.
Current assets and liabilities were recorded at book value which
approximates RV. Long-term liabilities were recorded at present values of
amounts to be paid and the pre-consummation stockholders' deficit was
adjusted to reflect the par value of pre-consummation equity interests.
The recorded value of the Series A Senior Preferred Stock (the "Senior
Preferred") to be issued pursuant to the Plan was determined based on the
difference between the RV of the Company's assets less the sum of (i) the
present value of liabilities plus (ii) the par value of pre-consummation
equity interests. The accretion of the difference between the recorded
value and the $10 per share redemption amount of the Senior Preferred will
be recorded as a reduction of income applicable to common stockholders over
a period of approximately 10 years.
The RV was determined by management on the basis of its best judgment of what
it considered to be the fair market value ("FMV") of the Company's assets and
liabilities at the time of the valuation after reviewing relevant facts
concerning the price at which similar assets were being sold between willing
buyers and sellers. However, there can be no assurances that the RV and the FMV
are comparable and the difference between the Company's calculated RV and the
FMV may, in fact, be material.
Pursuant to the provisions of the Plan, TGX provided for (i) the payment in
full of its secured debt by the issuance of new notes pursuant to the terms of a
restructured credit agreement, (ii) the conversion of substantially all of its
unsecured debt into two different series of preferred stock, (iii) tax and
priority and certain other specified classes of claims and interests arising
from options for common stock being paid in cash, retained or otherwise provided
for, and (iv) administrative claims being paid in cash or otherwise being
satisfied.
Three of the large administrative claimants (the "Opposing Administrative
Claimants") agreed that in full satisfaction of the balance of their
administrative claims they would receive (i) a payment of $300,000 (ii) 55,000
shares of Senior Preferred and (iii) the conveyance of approximately 29,400
acres of undeveloped land in Culberson and Hudspeth Counties, Texas. In
satisfaction of their unpaid administrative claims, all other administrative
claimants received cash and/or were entitled to receive promissory notes due
December 31, 1994 which were secured by certain assets of the Company. Such
notes were to be issued upon the execution of releases in favor of the Company
and others. As set forth in Note 3 below, administrative claimants received, in
1994, $150,000 as partial repayment of their notes prior to September 30, 1994.
Commencing in October 1994, the Company re-negotiated the terms of the notes
with certain administrative claimants and paid $389,000 in cash, issued 141,518
shares of Senior Preferred and also issued its non-recourse note in the amount
of $90,000 payable out of proceeds if any,
35
<PAGE>
from the NFG Litigation described in Note 4 below, in full satisfaction of
administrative notes with an aggregate of $1,220,000 in principal and interest
due at the time of renegotiation. The Company has continued to negotiate the
terms of the remaining outstanding administrative claims.
TGX was a party to numerous executory contracts which, pursuant to the
provisions of the Bankruptcy Code, could be assumed or rejected by TGX. If an
executory contract was assumed by TGX, all defaults related to the executory
contract were cured (generally, paid-in-full with cash). Currently, the
aggregate balance of pre-petition obligations related to assumed executory
contracts is approximately $317,000 which is related to undistributed net oil
and gas revenues which is in a "suspended pay" status. If an executory contract
was rejected by TGX, all claims related to the executory contract were satisfied
pursuant to the terms of the Plan.
As of the Effective Date, the preferred and common stockholders selected a new
Board of Directors (the "New Board") comprised of eight individuals to serve
until January 21, 1995 or until their successors were duly elected and
qualified. The New Board consisted of five members selected by holders of claims
to be satisfied with Senior Preferred (one of which cannot be an affiliate of
any holder of the Senior Preferred), two members selected by holders of Series B
Preferred Stock, 9% Cumulative Convertible Preferred Stock and the holders of
Common Stock acting as one class, and the final member is the chief executive
officer of TGX. Subsequent to the Effective Date, two members of the Board of
Directors resigned and have not been replaced. Subsequent to January 21,1995,
the eight members of the Board of Directors will be elected by all of the
Preferred and Common Stockholders voting as one class with the exception that,
pursuant to the terms of the Senior Preferred, since the Company has failed to
pay six quarterly dividends, at the next Annual Meeting, the Board of Directors
will be increased to ten and Senior Preferred Stockholders voting alone will be
entitled to select two additional Directors. The remaining Directors will be
elected by all stockholders voting as a class. Senior Preferred stockholders
have 95% of the voting power of all of the stockholders of the Company.
The Senior Preferred has a $10 per share redemption value and has a provision
for a 10% annual compounded cash dividend, payable quarterly, provided however,
that the payment of such dividend does not violate Delaware law or certain loan
covenants. The Company has not paid any of the dividends since the Effective
Date of the Plan and based on the current financial position of the Company,
does not expect to make any such dividend payments in the near future. Subject
to Delaware law, the Senior Preferred must be redeemed no later than
January 21, 2002.
3. LONG-TERM DEBT AND NOTES PAYABLE
As of December 31, 1994 and 1993, the components of long-term debt were:
------------------------------------------------
(Thousands) 1994 1993
------------------------------------------------
Bank borrowings:
Term loans (secured) $ - $ 19,209
Revolving credit (secured) 1,150 290
Non-recourse note 4,870 -
------------------------------------------------
6,020 19,499
Less current maturities - (19,499)
------------------------------------------------
Long-term debt $ 6,020 $ -
================================================
On July 13, 1994, the Company entered into a series of agreements with Bank
One, Texas N.A. ("Bank One") whereby the Company's then outstanding secured debt
with the Bank of Montreal ("BMO") was restructured and all existing BMO events
of default were resolved. Pursuant to the restructuring, Bank One established a
borrowing-based facility of $2,350,000 under which the Company immediately
borrowed $1,600,000 of which $1,452,000 was paid to BMO. The Bank One facility
bears interest at Bank One's stated rate plus two percent and is secured by
substantially all of the Company's oil and gas properties. The Bank One facility
at December 31,1994 had a borrowing base of $2,070,000 which is reduced by
$56,000 per month and is redetermined every six months or at Bank One's
discretion. The loan is repayable over 36 months and matures July 13, 1997. The
Bank One facility requires the maintenance of certain financial ratios including
a working capital ratio, after excluding certain liabilities and other
adjustments as allowed under the facility, of 1.2 to 1 and a tangible net worth,
including Senior Preferred stock, of a minimum of $5 million, and other
financial ratios. The Company was in compliance with all financial ratios and
covenants at December 31, 1994, but can give no assurance that it will be able
to continually meet the Bank One facility ratios and covenants.
36
<PAGE>
Simultaneously with the securance of the Bank One facility, BMO released all
of its liens on the Company's properties with the exception of its lien on the
Company's currently pending litigation with NFG ("NFG Litigation"). See Note 4
below.
Prior to restructuring its debt through receipt of the Bank One facility, the
Company had been subject to the terms of an Amended and Restated Credit
Agreement (the "Amended Credit Agreement') with BMO which was entered into in
February 1992 and amended thereafter and which essentially continued and
preserved the prior revolving credit agreement. Effective December 31,1992, the
Company had been notified by BMO that an event of default had occurred under the
Amended Credit Agreement, and as a result, BMO had the right to take certain
actions under such Amended Credit Agreement including, but not limited to, the
acceleration of all of the then outstanding BMO obligations. Pursuant to the
terms of the Amended Credit Agreement, as of December 31, 1993, the Company had
borrowings outstanding of $19,499,000 of which $9,316,000 bore interest at the
BMO prime rate plus 1.5%, $10,000,000 bore interest at 13%, and $183,000 bore no
interest.
In January 1994, in conjunction with the Company's sale of certain assets to
Belden & Blake Corporation ("BBC"), the Company made a debt service payment of
approximately $13,367,000 which included principal payments totaling $10,670,000
to BMO. The Company also made subsequent BMO principal payments of $2,949,000
before July 13, 1994. As set forth above, on July 13, 1994, in connection with
the series of agreements entered into between the Company and Bank One, the
Company paid approximately $1,452,000 to BMO which included a principal payment
of $1,424,000 and simultaneously therewith, BMO released all of its liens on the
Company's properties with the exception of its lien on the Company's currently
pending NFG Litigation. As part of the loan restructuring, BMO converted
$4,652,000 (the "BMOF Principal") of its outstanding indebtedness, including
legal transaction costs incurred by BMO, to a non-recourse note secured only by
the NFG Litigation and any proceeds that might be received therefrom. BMO
assigned its rights to the loan, security, and the Company's note to BMO's
wholly owned subsidiary, BMO Financial, Inc. ("BMOF"). Pursuant to agreement,
after repayment of the outstanding BMOF Principal, plus applicable interest,
from NFG Litigation proceeds, if any, BMOF will, in certain instances, after the
Company has received the same amount as was paid to BMOF, be entitled to receive
up to 50% interest in certain additional litigation proceeds. If NFG Litigation
proceeds are insufficient to repay the BMOF Principal, plus applicable interest,
the Company will have no further obligation for such repayment. The BMOF note
matures on December 31,1997, subject to each party having the right to extend
the maturity date and bears interest at the rate of 10% per annum. However,
until December 31, 1997, and for such further time as BMOF elects to extend the
maturity date of such loan, no cash payment for such interest is required;
instead, the Company will pay interest in kind through the issuance of
additional notes to BMOF. As of December 31, 1994, total accrued interest
pursuant to the BMOF note was $218,000 resulting in total BMOF debt of
$4,870,000. Due to the complexities of the NFG Litigation and the significant
uncertainties therewith, the ultimate amount of NFG Litigation proceeds cannot
be reasonably estimated.
During the Reorganization Proceeding, the Company incurred and claimants filed
applications for approximately $7,131,000 in administrative fees and expenses
relating to the reorganization ("Administrative Claims"). The Company objected
to certain of the Administrative Claims and negotiated settlement amounts and
terms of payment with certain holders of Administrative Claims. As a result,
administrative claimants, other than the Opposing Administrative Claimants, upon
execution of certain releases in favor of the Company and others, were entitled
to receive promissory notes (the "Administrative Notes") due December 31,1994 in
satisfaction of each of their unpaid administrative claim. Substantially all
administrative claimants entitled to receive Administrative Notes perfected
their claims by executing such releases. The Administrative Notes bear interest
at a rate not to exceed 8% and are secured with certain collateral (the
"Consummation Collateral"). If the proceeds related to the Consummation
Collateral are not sufficient to satisfy the Company's obligations under the
Administrative Notes the Company's excess operating funds, if any, will be
applied toward the balances due. During the last quarter of 1994, the Company
negotiated with substantially all of those persons holding Administrative Notes.
As a result, Administrative Notes totaling approximately $990,000 in principal
and $230,000 in accrued interest were renegotiated with the Company paying in
the aggregate $389,000 in cash, issuing 141,518 shares of Senior Preferred Stock
and further issuing its non-recourse note in the aggregate amount of $90,000
payable out of proceeds, if any, received by the Company from the NFG
Litigation. As a result of Administrative Notes renegotiations, the Company
secured forgiveness of $831,000 of such notes and accordingly reflected an
extraordinary gain of that amount.
Cash basis interest expense paid during 1994, 1993 and 1992 totaled
approximately $3,364,000, $774,000, and $1,050,000 respectively.
37
<PAGE>
4. COMMITMENTS AND CONTINGENCIES
NFG Litigation
Since November 30, 1984, TGX has been involved in litigation in the United
States District Court for the Western District of New York ("New York Federal
Court") (Civ. No. 84-1372-E) with NFG concerning the validity of a contract (the
"Contract") pursuant to which TGX (as successor-in-interest to Paragon
Resources, Inc. ("Paragon"), the original contracting party) sells certain
natural gas production to NFG. The litigation addresses, among other things, the
continued validity of the Contract, the price for natural gas sold, and certain
take-or-pay claims.
In December 1983, certain pricing provisions of the Contract were disapproved
by the New York Public Service Commission ("PSC") and as a result, in January
1991, the New York Federal Court determined that the Contract was invalidated.
However, on December 3, 1991, the Court of Appeals for the Second Circuit
("Court of Appeals") (Case No. 91-7127) reversed the New York Federal Court and
held that the Contract remains in effect subject to the pricing provisions set
forth therein. The Court of Appeals remanded the case to the New York Federal
Court for further proceedings not inconsistent with the opinion of the Court of
Appeals.
During the Reorganization Proceeding, TGX filed an adversary proceeding (the
"Turnover Proceeding") in the Bankruptcy Court to compel NFG to pay the amount
due to TGX pursuant to the provisions of the Contract. Effective June 19,1992,
TGX and NFG entered into a partial settlement agreement regarding the settlement
of some, but not all, of their disputes. Pursuant to the provisions of the
partial settlement agreement, in consideration of a payment of $2,940,000 (the
"Payment") from NFG, which is reflected in Other Revenues for the period January
1 through October 1,1992, TGX (i) dismissed the Turnover Proceeding without
prejudice (ii) released NFG (subject to certain limitations) from any and all
liability and affirmative claims for relief alleged to arise from or based upon
certain evidence presented by TGX in the Turnover Proceeding, and (iii) reserved
its rights regarding the assumption or rejection of certain other relatively
minor gas purchase agreements with NFG. The Payment will be credited against any
amount due to TGX from NFG.
In July 1992, the New York Federal Court denied a motion filed by NFG for
partial summary judgment wherein NFG sought a finding that it had properly
suspended performance under, and eventually terminated, the Contract. A
subsequent rehearing upheld this conclusion, but determined that certain matters
relating to this issue were questions of fact that cannot be resolved by summary
judgment.
In December 1992, NFG filed a motion with the PSC requesting a hearing to
determine pricing issues related to the Contract. In 1993, the PSC determined
that it would hold the requested hearing, and in November 1994, the
Administrative Law Judge ("ALJ") appointed by the PSC issued a preliminary
Recommended Decision stating that the PSC should find that, from December
20,1983 through November, 1992, the maximum contract price that would be just
and reasonable within the meaning of the Public Service Law has been $3.714 per
Mcf of gas. The ALJ also recommended that the Commission should determine only
NFG's entitlement to cost recovery from its customers, and should not adjudicate
the respective rights of TGX and NFG vis-a-vis one another. TGX, NFG and the
staff of the PSC have filed exceptions to the ALJ's recommended rulings, but,
the PSC had not ruled on the recommended decision or the filed exceptions prior
to March 1, 1995.
In January 1993, the New York Federal Court granted TGX's motion for partial
summary judgment regarding the price to be paid under the Contract. Based on the
New York Federal Court's order, TGX has concluded that from December 1983, until
at least, January 1, 1993, the date Federal price controls were terminated, the
Contract price is equal to the lower of (i) the applicable maximum lawful price
for December 1983 and for each month thereafter as established by the Natural
Gas Policy Act ("NGPA") subject to the escalations provided by the NGPA or (ii)
the December 1983 permitted Contract price of approximately $4.41 per MCF. The
Federal Court's decision might be interpreted such that the December 1983
permitted contract price would be $4.41 per Mcf during the winter months and
$4.01 per Mcf during the summer months. Based on TGX's calculations, the gross
difference between the price actually paid by NFG and the price required by the
New York Federal Court's order (assuming a contract price of $4.41 for winter
and $4.01 for summer per Mcf) is approximately $23,912,000 as of December
31,1994, including permitted statutory interest. The New York Federal Court's
order did not determine the impact of the termination of the NGPA, the effect of
any subsequent PSC order or NFG's defense, including the alleged repudiation by
TGX of the NFG contract. As part of its sale of substantially all of its oil and
gas properties in Ohio and New York to BBC, TGX assigned the Contract effective
December 1, 1993. TGX's assignment of the contract did not include TGX's rights
in its existing claims against NFG, any proceeds therefrom, and TGX's rights,
claims or causes of action, even if they had not yet been asserted, that arose
prior to the effective time of the assignment.
38
<PAGE>
In November 1994, the New York Federal Court appointed a Magistrate to review
and hear various aspects of the Federal Court Litigation, including certain
motions, scheduling, and certain pre-trial discovery. In early 1995, in
anticipation of the issuance of a decision by the PSC in March 1995, the
Magistrate held that all discovery would be stayed pending a further meeting
with the Magistrate in May 1995 to discuss the state of the case.
New York Department of Environmental Conservation
In January 1990, the New York State Department of Environmental Conservation,
Division of Mineral Resources ("DEC") notified TGX that it considered TGX to be
in violation of certain provisions of the environmental conservation laws of the
State of New York concerning approximately 150 natural gas wells and production
facilities located in Chautauqua and Erie Counties. To settle this dispute, TGX
entered into a consent order (the "Agreed Order"), which among other things
required TGX to provide a letter of credit in the amount of $300,000 which was
to be utilized by the DEC if TGX did not comply with the Agreed Order. The
letter of credit was provided by BMO but was secured by $300,000 in cash. Such
security is released as the letter of credit is reduced or eliminated. In May
1994, the DEC agreed to reduce the letter of credit amount to $150,000 and a
like amount of cash collateral was released. In February 1995, TGX's obligation
to maintain the letter of credit was eliminated and the remaining cash
collateral released.
Other
In August 1992, certain unleased mineral interest owners commenced a legal
action against TGX, as operator of certain wells, in the 19th Judicial District
Court for East Baton Rouge Parish, Louisiana (Case Number 383844, Division "A").
The complaint alleges that revenues in excess of the reasonable costs of
drilling, completing, and operating certain wells have not been credited to the
interests of the unleased mineral interest owners. This case is in the discovery
stage and if settlement negotiations are not successful, TGX will vigorously
defend itself in the litigation.
In March 1994, a hearing was conducted in the Bankruptcy Court regarding the
final allowance of pre-petition and administrative claims related to an
overriding royalty interest previously conveyed by TGX. As a result of this
hearing, the Bankruptcy Court established the method for computing these claim
amounts. The parties stipulated that the finally allowed pre-petition claim
amount was $600,000 which has been satisfied with the issuance of Senior
Preferred. Previously, the Company had estimated this claim amount and therefore
it had been included in the financial statements for prior years. Pursuant to
the Bankruptcy Court's order, certain post-petition but prior to October 2, 1992
claims are to be treated as administrative claims. The administrative claim
amount will be calculated by the claimant, subject to review and approval by the
Company, and pursuant to the terms of the Plan. Any claims subsequent to
October 2, 1992 are subject to the Bankruptcy Court's review, including
ownership of the overriding royalty interest.
From time to time, in the normal course of business, the Company is a party to
various other litigation matters the outcome of which, to the extent not
otherwise provided for, should not have a material adverse effect on the
Company.
Leases
As of December 31, 1994, the Company's only lease commitment was for the
remaining term of its office lease for 1995 and 1996 of $83,000 and $7,000,
respectively.
During 1994, the Company canceled its capitalized computer lease due to the
out sourcing of certain financial operations.
5. INVESTMENT IN NATURAL GAS TREATING PLANT
In conjunction with the acquisition of Amarex, Inc. in 1985, the Company
acquired an interest in the Comite Field Plant Venture (the "Venture"), an
Oklahoma general partnership formed in April 1982 for the purpose of
constructing and operating a natural gas treating plant to serve the Comite
Field in East Baton Rouge Parish, Louisiana. Natural gas produced from wells
operated by the Company and one other operator is transported to the plant where
contaminants are extracted to satisfy pipeline specifications. In addition, the
plant also provides condensate handling
39
<PAGE>
and saltwater disposal facilities. The Company receives cash distributions from
the Venture for its share of net cash flow.
A summary of the Venture's unaudited financial position as of
December 31,1994,1993, and 1992 and the results of its operations for each of
the three years in the period ended December 31, 1994, is:
(Unaudited)
===============================================================
(Thousands) 1994 1993 1992
---------------------------------------------------------------
SUMMARY BALANCE SHEETS
Current assets $ 869 $ 438 $ 490
Net property and equipment 2,169 2,650 3,123
---------------------------------------------------------------
$ 3,038 $ 3,088 $ 3,613
===============================================================
Current liabilities $ 380 $ 76 $ 322
Long-term debt 150 200 -
Partners' capital 2,508 2,812 3,291
---------------------------------------------------------------
$ 3,038 $ 3,088 $ 3,613
===============================================================
SUMMARY STATEMENTS OF EARNINGS
Fees earned $ 2,327 $ 2,767 $ 2,579
Operating expenses 1,142 1,284 1,307
---------------------------------------------------------------
Operating income 1,185 1,483 1,272
Other income 11 7 4
---------------------------------------------------------------
Net income $ 1,196 $ 1,490 $ 1,276
===============================================================
6. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
As of December 31, 1994 and 1993, the primary components of accounts payable
and accrued expenses were (in thousands):
1994 1993
---- ----
Accounts payable $ 489 $ 664
Undistributed net oil and natural
gas revenue 1,069 1,584
Accrued interest and fees 32 3,408
Accrued pre-petition liabilities 934 926
Miscellaneous accruals 828 974
------- -------
$ 3,352 $ 7,556
======= =======
7. REDEEMABLE SENIOR PREFERRED STOCK
The Company is authorized to issue 10,000,000 shares of Series A Redeemable
Senior Preferred Stock ("Senior Preferred") with a par value of $1 per share.
The Senior Preferred entitles its holders to receive a 10% annual compounded
cash dividend, payable quarterly, provided however, that the payment of such
dividend does not violate Delaware law or certain covenants in the Company's
bank loan agreements. The Company has not paid any of the quarterly dividends
required to date and based on the Company's current financial position does not
expect to make any such dividend payments in the near future. The Senior
Preferred have a liquidation preference of $10 per share and have priority over
the liquidation preference afforded the holders of Series B Preferred Stock (the
"Junior Preferred"), 9% Cumulative Convertible Preferred Stock (the "Old
Preferred") and Common Stock. The Senior Preferred are scheduled to be redeemed
on January 21,2002 ("Redemption Date"). On a monthly basis, the accretion of the
difference between the recorded value and the redemption amount of the Senior
Preferred is reflected as a reduction of income applicable to common
stockholders. Since the Senior Preferred have both debt and equity
characteristics it is not classified as a component of equity. Holders of Senior
Preferred have 95% of the voting rights of the Company with the remaining 5% of
voting rights being allocated collectively among the holders of the Junior
Preferred, Old Preferred and Common Stock.
Pursuant to the Plan, the Company provided for a total of 8,529,246 shares to
be issued to holders of certain unsecured claims on the basis of one share of
Senior Preferred for every $10 of certain finally allowed or otherwise agreed
upon claim. During 1992, an additional 200,000 shares were issued to an
executive officer pursuant to a management agreement. As of December 31, 1994,
1,498,534 Senior Preferred shares have actually been issued.
40
<PAGE>
All remaining shares are anticipated to be issued during 1995 as a result of a
compromise settlement with the Senior Subordinated Notes holder trustee in late
1994. In conjunction with fresh start reporting, the Senior Preferred was
recorded at a value of $11,046,000 which is $76,246,000 less than its redemption
value. The Company recorded in 1994 and 1993 $99,000 and $134,000, respectively,
of stock compensation expense related to the 1992 management agreement. Stock
compensation expense is amortized over the stock award forfeiture period of two
years from grant date. For stock compensation expense recognition purposes the
1992 award was valued at $1.50 per share, based on an internal estimate of
Company net assets as of October 2, 1992 (fresh start reporting).
Since December 31,1991, the components of the number of shares of the
Company's Senior Preferred and changes in associated values are as follows (in
thousands):
-----------------------------------------------------------------------
Number Recorded
of shares Value
-----------------------------------------------------------------------
Balance, December 31, 1991 - $ -
Shares to be issued net of effect
of fresh start reporting 8,729 11,046
Accrued and unpaid dividends - 5,440
Accretion on redemption value
and dividends - 629
-----------------------------------------------------------------------
Balance, December 31, 1992 8,729 17,115
Accrued and unpaid dividends 9,869
Accretion on redemption value
and dividends 2,895
Amortization of compensation shares
pursuant to management agreement 134
-----------------------------------------------------------------------
Balance, December 31, 1993 8,729 30,013
Accrued and unpaid dividends 10,510
Accretion on redemption value and
dividends 3,980
Amortization of compensation shares
pursuant to management agreement 99
-----------------------------------------------------------------------
Balance, December, 1994 8,729 $ 44,602
=======================================================================
8. STOCKHOLDERS' EQUITY (DEFICIT)
Since December 31,1991, the components of the number of shares of the
Company's stockholders' equity (deficit) and the changes therein are:
----------------------------------------------------------------------
Old
Preferred Common Treasury
(Thousands of shares) Stock Stock Stock
----------------------------------------------------------------------
Balance, December 31, 1991 300 28,977 (3,663)
Dividends on Old Preferred Stock 77 - -
Effect of fresh start reporting - (3,663) 3,663
----------------------------------------------------------------------
Balance, December 31, 1992 377 25,314 -
Dividends on Old Preferred Stock 27 - -
----------------------------------------------------------------------
Balance, December 31, 1993 404 25,314 -
Dividends on Old Preferred Stock 27 - -
----------------------------------------------------------------------
Balance December 31, 1994 431 25,314 -
======================================================================
41
<PAGE>
Since December 31, 1991, the components of the Company's stockholders' equity
(deficit), and the changes therein are:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
Old Additional Retained
Preferred Common Paid-In Earnings Treasury
(Thousands) Stock Stock Capital (Deficit) Stock
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Balance, December 31, 1991 $ 300 $ 290 $ 89,409 $(147,088) $ (8,348)
Post-petition dividends on Old
Preferred, payable with additional
shares of Preferred 70 - 633 (203) -
Dividends on Senior Preferred - - - (6,075) -
Discount on Senior Preferred dividends - - - 2,631 -
Net loss - - - (1,269) -
Effect of fresh start reporting - - (89,409) 152,004 8,348
- ------------------------------------------------------------------------------------------------------------------------------------
Balance, October 2, 1992 370 290 633 - -
Post-petition dividends on Old Preferred,
payable with additional shares of
Old Preferred 7 - 60 (67) -
Dividends on Senior Preferred, net - - - (2,238) -
Accretion of Senior Preferred
redemption value - - - (629) -
Net loss - - - (250) -
- ------------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1992 377 290 693 (3,184) -
Preferred dividends, payable with additional
shares of Old Preferred 27 - 243 (270) -
Dividends on Senior Preferred, net - - - (9,869) -
Accretion of Senior Preferred redemption value - - - (2,895) -
Net loss - - - (13,917) -
- ------------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1993 404 290 936 (30,135) -
Preferred dividends, payable with
additional shares of Old Preferred 27 - 243 (270) -
Dividends on Senior Preferred, net - - - (10,510) -
Accretion of Senior Preferred redemption value - - - (3,980) -
Net loss - - - (716) -
- ------------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1994 $ 431 $ 290 $ 1,179 $ (45,611) -
====================================================================================================================================
</TABLE>
Series B Preferred Stock
The Company is authorized to issue Series B Preferred Stock (the "Junior
Preferred") with a $1 par value and a liquidation preference of $10 per share,
which may be redeemed by the Company in whole or in part at any time at a price
per share equal to the liquidation preference amount per share, plus all accrued
and unpaid dividends through the date of redemption. The Junior Preferred will
be used to satisfy certain claims pursuant to the Plan that have been finally
allowed. To date, no claims to be satisfied with the Junior Preferred have been
allowed and the Company does not currently anticipate that any such claims will
be allowed.
Cumulative Convertible Preferred Stock
The Company is authorized to issue 10,000,000 shares of 9% Cumulative
Convertible Preferred Stock (the "Old Preferred"), of which 300,000 shares are
outstanding. The Old Preferred have a $1 par value and a liquidation preference
of $10 per share, convertible at any time at the rate of one Old Preferred share
for four shares of the Company's Common Stock. In addition, 131,000 shares of
Old Preferred will be issued for accrued dividends. Until the redemption value
plus all accrued dividends attributable to Senior Preferred are paid in full,
dividends related to the Old Preferred will be paid with additional shares of
Old Preferred.
42
<PAGE>
Common Stock
The Company is authorized to issue 100,000,000 shares of Common Stock, with a
$.01 par value, of which 25,313,533 were outstanding at December 31, 1994. All
outstanding shares of Common Stock are fully paid and non-assessable.
The holders of Common Stock are entitled to one vote per share upon all
matters presented to them. Pursuant to the Plan, holders of Common Stock are
entitled, collectively with holders of Junior Preferred and Old Preferred, to 5%
of the total voting power of the Company. The holders of Common Stock are
entitled to dividends in such amounts as may be declared from time to time out
of any funds legally available for such purposes. However, no dividends are
payable until all accrued dividends have been paid to the preferred
stockholders. In the event of liquidation, dissolution or winding up of the
affairs of the Company, whether voluntary or involuntary, after payment of debts
and liquidation preferences on preferred stock, all remaining assets, if any,
will be divided and distributed among the holders of Common Stock pro rata
according to the number of shares owned by them. The Common Stock does not have
preemptive rights and is not subject to redemption.
Restricted Stock and Stock Options Plans
Previously, the Company had adopted a key employee compensation package which
consisted of a Restricted Stock Plan, a Non-Qualified Stock Option Plan, and an
Incentive Stock Option Plan. Both the Non-Qualified Stock Option Plan and the
Incentive Stock Option Plan were terminated in 1991 pursuant to the respective
plan's provisions and while options previously issued are still valid, no new
options under these plans can be issued.
Shares of common stock under the Restricted Stock Plan were granted free of
charge to the recipient in consideration for services rendered. Grants made
under the plan are subject to forfeiture, based on a formula, in the event the
recipient leaves the employment of the Company within three, four or five years
after the date of grant. The market value of the Common Stock on the date of
grant was charged to expense over a five-year period, regardless of whether or
not the shares are ultimately earned by the employee. The Company has reserved
89,333 shares of Common Stock for issuance under the plan. In 1991 through 1994,
no shares of common stock were issued to vested participants pursuant to the
plan and no new grants will be issued under this plan.
Non-qualified and incentive stock options were granted to selected key
employees at an exercise price equal to the market price of the shares of common
stock on the date of grant, and become exercisable over a five-year period.
Information relating to stock options granted under both plans is as follows:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
Non-Qualified Plan Incentive Plan
------------------- -------------------
<S> <C> <C> <C> <C>
Average Average
Number Exercise Number Exercise
of Price of Price
Shares Per Share Shares Per Share
- --------------------------------------------------------------------------------
Balance, December 31, 1991 11,400 $ 7.76 60,500 $ 1.55
Options canceled or forfeited - - (12,000) 2.17
- --------------------------------------------------------------------------------
Balance, December 31,1992 11,400 $ 7.76 48,500 $ 1.40
Options canceled or forfeited (11,400) 7.76 (4,000) 4.00
- --------------------------------------------------------------------------------
Balance, December 31, 1993 - - 44,500 $1.17
Options canceled or forfeited - - (40,000) 1.15
- --------------------------------------------------------------------------------
Balance, December 31,1994 - - 4,500 $ 1.33
================================================================================
Options exercisable:
December 31, 1992 11,400 $ 7.76 34,500 $ 1.55
December 31, 1993 - - 37,500 $ 1.22
December 31, 1994 - - 4,500 $ 1.33
</TABLE>
9. INCOME TAXES
On October 2,1992, the Company, concurrent with the implementation of fresh
start reporting, adopted Statement of Financial Accounting Standards No. 109,
"Accounting for Income Taxes" ("Statement 109"), which requires recognition of
deferred tax assets and liabilities for the expected future tax consequences of
events that have been included in the financial statements or tax returns. Under
this method, deferred tax liabilities and assets
43
<PAGE>
are determined based on the difference, if any, between the financial reporting
and tax bases of assets and liabilities using enacted tax rates in effect for
the year in which the differences are expected to reverse. Prior to the adoption
of Statement 109, deferred income taxes were provided for timing differences
arising from the recognition of revenues and expenses in different periods for
financial and tax reporting purposes.
Long-term deferred tax assets (liabilities) are comprised of the following for
the years 1994,1993 and 1992, respectively.
- --------------------------------------------------------------------------------
December 31, December 31, December 31,
(Thousands) 1994 1993 1992
- --------------------------------------------------------------------------------
Deferred Tax Assets:
Loss carry forwards $ 11,084 $ 9,712 $ 7,070
AMT credit carry forward
and other 150 9 -
Deferred Tax Liabilities:
Oil & gas properties (2,303) - (2,009)
----------- ----------- -----------
Net deferred tax asset 8,931 9,721 5,061
Valuation allowance (8,931) (9,721) (5,061)
- --------------------------------------------------------------------------------
$ - $ - $ -
================================================================================
Income tax expense differs from the amounts computed by applying the statutory
federal rate as follows:
- --------------------------------------------------------------------------------
Year Ended Year Ended Year Ended
December 31, December 31, December 31,
1994 1993 1992
- --------------------------------------------------------------------------------
Income taxes computed at
statutory federal rate 34.0% (34.0)% (34.0)%
Net operating loss carryover not
deductible (utilized) in
current period (34.0) 34.0 34.0
Alternative minimum tax and other 1.1 - -
- --------------------------------------------------------------------------------
1.1% -% - %
================================================================================
Pursuant to the provisions of the Internal Revenue Code (the "Code"), a
corporation which undergoes a "change of ownership" is generally subject to an
annual limitation on the utilization of its loss carryovers. As a result of the
Reorganization Proceeding, on the Effective Date a "change of ownership" for the
Company occurred under the Code. Since the Reorganization Proceeding was
conducted pursuant to the Bankruptcy Code, the Company was eligible for an
exception (the "Bankruptcy Exception") to this general rule. In order to
maintain the Bankruptcy Exception, the Company could not have another "change of
ownership" within two years of the first change. If such a change did occur, the
Company's entire pre-"change of ownership" loss carryovers would be eliminated.
Due to the probability that a second "change of ownership" for tax reporting
purposes could occur, the Company elected out of the Bankruptcy Exception
regarding the utilization of its pre-"change of ownership" loss carryovers.
Since the Company has elected not to apply the Bankruptcy Exception, the
Company is limited in its utilization of the pre-"change of ownership" loss
carryovers. Based on the value of the Company as of the Effective Date, the
annual amount of the pre-"change of ownership" loss carryovers to be utilized is
limited to $1,230,000 but loss carryovers not fully utilized in the year that
they are available may be carried over and utilized in subsequent years, subject
to their expiration provisions. As of December 31, 1994, the Company had pre-
"change of ownership" net operating loss carryforwards of $2,417,000 which are
available for use through 2006. These loss carryforwards may be increased by any
built-in gain exclusion recognized during the five year period after the "change
of ownership". The Company also had post-"change of ownership" net operating
loss carryforwards of $7,701,000 that expire 2008 and are available without
limitation.
The Company has certain investment tax credits which are also subject to the
"change of ownership" limitation. Due to the limitation and scheduled
expiration, it is unlikely that the Company will realized any future benefit
from such credits. The Company had depletion carryforwards, as of
December 31, 1994, of $14,234,000 which are limited annually to 65% of
taxable income.
44
<PAGE>
10. RELATED PARTY TRANSACTIONS
Pursuant to the provisions of the applicable agreements and in its capacity as
general partner, the Company receives recurring supervisory and administrative
fees, including reimbursement of certain general and administrative costs, from
certain partnerships. Supervisory and administrative fees of $684,000, $852,000
and $958,000, were received during 1994, 1993, and 1992, respectively.
Since certain affiliated partnerships have not had sufficient cash flows to
repay their obligations, accounts and notes receivable from these affiliated
partnerships in which TGX is a general partner have been written-off.
Accordingly, the Company has been applying 100% of the net revenues of the
respective partnerships to their obligations due to TGX and will continue to do
so until the amounts due have been repaid or until the partnerships are
liquidated. As a result of 1994 partnership liquidations, the Company obtained
additional direct interests in related oil and natural gas properties having an
estimated value of $381,000 and realized the recoupment of $751,000 in previous
allowed for receivables and notes.
Presented below are aggregate amounts due from partnerships and other
affiliates:
----------------------------------------------------------------------
(Thousands) 1994 1993
----------------------------------------------------------------------
Accounts receivable from affiliates
(current) $ 504 $1,154
Accounts and notes receivable from affiliates
(noncurrent) - 100
----------------------------------------------------------------------
$ 504 $1,254
======================================================================
Paragon and certain of its affiliates are the owners of approximately 14% of
the Company's outstanding Common Stock. In the past, the Company has had
substantial transactions with Paragon including the offering of interests and in
the drilling of wells for partnerships.
Included in the above 1994 and 1993 amounts due from its affiliates, net of
allowance for possible uncollectibility, is $286,000 and $284,000, respectively,
due from Paragon and certain of its affiliates. In February 1992, the Company
commenced a legal action regarding the collection of the amount due to it from
Paragon and certain of its affiliates. Due to the uncertainty regarding the
status of this litigation, the Company established an allowance for all amounts
due from Paragon and affiliates in 1994 and 1993 in excess of $286,000 and
$284,000, respectively. The total allowance for affiliated receivables in 1994
and 1993 was $2,027,000 and $1,963,000, respectively.
During 1992, the Company entered into an agreement with a member of its Board
whereby the Company sold certain oil and gas properties to an affiliate of the
Board member for $269,000. This sale was approved by the Board, with the
involved Board member abstaining from both the discussion and vote. The Company
had solicited bids for the properties and, through this transaction, the
properties were sold to the highest bidder.
11. MAJOR CUSTOMERS
The Company's revenues are derived principally from uncollateralized sales to
customers in the oil and natural gas industry. The concentration of credit risk
in a single industry affects the Company's overall exposure to credit risks
since customers may be similarly affected by changes in economic and other
conditions.
Customers which accounted for greater than 10% of oil and gas sales are as
follows:
1994 1993 1992
----- ----- -----
Lion Oil Company 14% - -
National Fuel Gas Distribution Corporation - 24% 33%
Noram Energy Services Inc. 12% - -
Princeton Natural Gas Company 15% - -
12. INFORMATION ON OIL AND GAS ACTIVITIES (UNAUDITED)
Following are supplemental unaudited disclosures relating to the Company's oil
and natural gas exploration and production activities.
45
<PAGE>
Oil and Gas Related Costs and Operating Results
The following schedules present capitalized costs and costs incurred, whether
capitalized or expenses, and operating results for the periods then ended.
- --------------------------------------------------------------------------------
October 2, January 1,
through through
December' 31, October 1,
(Thousands) 1994 1993 1992 1992
- --------------------------------------------------------------------------------
Capitalized costs:
Proved properties $ 10,407 $ 11,434 $ 39,414 $ 39,347
Accumulated depletion
and depreciation (3,251) (2,281) (817) -
- --------------------------------------------------------------------------------
$ 7,156 $ 9,153 $ 38,597 $ 39,347
================================================================================
Costs incurred:
Acquisition of properties:
Unproved $ - $ - $ - $ -
Proved - - - -
Development(1) 404 179 67 154
- --------------------------------------------------------------------------------
$ 404 $ 179 $ 67 $ 154
================================================================================
Operating results*:
Revenues $ 4,802 $ 9,730 $ 2,641 $ 6,501
Costs and expenses:
Production costs 3,188 3,935 1,003 2,965
Depletion and
depreciation 1,099 2,607 817 3,215
- --------------------------------------------------------------------------------
4,287 6,542 1,820 6,180
Operating earnings before
income taxes 515 3,188 821 321
Income tax expense 17 - - -
- --------------------------------------------------------------------------------
Operating earnings $ 498 $ 3,188 $ 821 $ 321
================================================================================
* Excludes general and administrative and interest expense.
(1) 1994 and 1993 activity represents primarily properties received in
settlement of certain partnership notes and receivables.
Proved Reserves
The following table, which includes proved undeveloped reserves as extensions
and discoveries in 1994 and for 1993 takes into consideration the sale of New
York and Ohio properties by the Company to BBC on January 14, 1994, but
effective December 1, 1993, presents estimates of proved oil and natural gas
reserves, all of which are located in the United States. Proved reserves are
estimated quantities of oil and natural gas which geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions. Proved-
developed reserves are those which are expected to be recovered through existing
wells with existing equipment and operating methods. Reserves are stated in
thousands of barrels of oil and billions of cubic feet of natural gas.
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------
1994 1993 1992
---- ---- ----
Oil(MBls) Gas(Bcf) Oil(MBls) Gas(Bcf) Oil(MBls) Gas(Bcf)
----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves:
Beginning of year 525 9.1 980 72.2 1,112 73.3
Sales of reserves in place (37) (.5) (111) (62.0) (139) (1.6)
Extensions and discoveries 487 2.6
Revisions of previous estimates 18 1.4 (257) 2.6 89 4.0
Production (62) (2.2) (87) (3.7) (82) (3.5)
----------------------------------------------------------------------------------------------------------------
End of year 931 10.4 525 9.1 980 72.2
================================================================================================================
Proved-developed reserves 444 7.8 525 9.1 980 72.2
================================================================================================================
</TABLE>
The above reserve estimates include for the first time in 1994, as extensions
and discoveries, estimates of previously discovered proved undeveloped reserves.
Due to the uncertainty in prior years of the Company's ability to finance their
development, proved undeveloped reserves were not included in reported reserves.
However, as a result of the Company's improving financial condition, it
anticipates that sufficient funds will be available in 1994 and beyond to
develop these reserves.
46
<PAGE>
Geological and engineering estimates of proved oil and natural gas reserves
are highly interpretive, inherently imprecise, and subject to ongoing revisions
that may be substantial in amount. Although every reasonable effort is made to
ensure that the reserve estimates reported represent the most accurate
assessments possible, these estimates are by their nature generally less precise
than other estimates presented in connection with financial statement
disclosures.
Standardized Measure of Discounted Future Net Cash Flows
The following table presents the standardized measure of estimated discounted
future net cash flows attributable to the Company's proved oil and gas reserves
("Standardized Measure"), and an analysis of the changes in these amounts and
quantities for the periods indicated. For 1994, proved undeveloped reserves are
included as extensions and discoveries, and 1993 excludes the New York and Ohio
properties which were sold to BBC. The Standardized Measure was computed on the
basis of (a) contractual prices, including escalations for natural gas, in
effect at year end for oil and natural gas (b) the estimated market price for
natural gas and the posted price for oil in effect at year end in the case of
properties being commercially developed but not covered by existing contracts,
(c) estimated deliverability, which not only considers the physical
characteristics of the well or properly, but also the estimated future prices to
be received by the Company and the amount and timing of future production
estimated to be taken by its purchasers, (d) where applicable, the premise that
future prices and takes will be in accordance with existing contractual terms
which may require arbitration or litigation to ultimately assure compliance, (e)
for 1992 natural gas reserves dedicated under the NFG Contract, the 90% of No. 6
Fuel Oil Price (see Note 4 for a description of litigation related to the
Contract). Estimated future production and development costs are based on
economic conditions at the respective year ends. Future income taxes, if any,
are computed by applying statutory income tax rates to the difference between
the future pre-tax cash flows and the tax basis of proved oil and gas
properties, after considering investment tax credits and depletion carryforwards
and net operating loss carryovers associated with these properties.
Since the Standardized Measure was prepared using the prevailing economic
conditions existing at each applicable year end, it is emphasized that such
conditions continually change, as evidenced by the fluctuations in oil and
natural gas prices during recent years. Accordingly, such information should not
serve as a basis in making any judgment on the potential value of the Company's
recoverable reserves, or in estimating future results of operations.
----------------------------------------------------------------------
(Thousands) 1994 1993 1992
----------------------------------------------------------------------
Future net cash flows:
Future revenues $ 29,092 $ 27,054 $214,888
----------------------------------------------------------------------
Future production costs 10,631 10,369 80,798
Future development costs 3,647 607 940
----------------------------------------------------------------------
14,278 10,976 81,738
----------------------------------------------------------------------
Future pre-tax cash flows 14,814 16,078 133,150
Future income taxes - - -
----------------------------------------------------------------------
$ 14,814 $ 16,078 $133,150
======================================================================
Standardized Measure, discounted at 10%:
Future pre-tax cash flows $ 8,807 $ 10,943 $ 46,429
Future net cash flows 8,807 10,943 46,429
======================================================================
Changes in Standardized Measure:
Standardized Measure, beginning
of year $ 10,943 $ 46,429 $ 47,309
======================================================================
Sale of reserves in place (1,042) (31,832) (1,968)
Extensions and discoveries (1) 2,213 611 -
Revisions of previous quantity
estimates 1,072 461 2,787
Changes in future development costs (2,310) 185 181
Net changes in prices and production
costs (2,858) (2,011) (133)
Sales of oil and natural gas produced,
net of production costs (1,614) (5,795) (5,174)
Net change in income taxes - - -
Accretion of discount 1,094 4,643 4,731
Changes in production rates and
other, net 1,309 (1,748) (1,304)
----------------------------------------------------------------------
Net decrease (2,136) (35,486) (880)
----------------------------------------------------------------------
Standardized Measure, end of year $ 8,807 $ 10,943 $ 46,429
======================================================================
(1) Reflects inclusion, in 1994, of proved undeveloped reserves excluded in
prior years' reporting.
47
<PAGE>
13. INTERIM FINANCIAL DATA (UNAUDITED)
The unaudited interim results of operations for 1992, 1993, and 1994 adjusted
for discontinued operations related to LEDCO, are summarized below (in thousands
of dollars except per share amounts):
July 1, October 2
through through
1992: March 31, June 30, October 1, December 31,
- --------------------------------------------------------------------------------
Revenues $ 2,297 $ 3,669 $ 3,864 $ 2,993
Gross profit 994 1,209 1,376 1,595
Net income (loss) applicable
to common stock (4,009) (1,998) 1,091 (3,184)
Income (loss) per common
share $ (.16) $ (.08) $ .05 $ (.13)
================================================================================
1993: March 31, June 30, September 30, December 31,
- --------------------------------------------------------------------------------
Revenues $ 2,404 $ 2,903 $ 2,544 $ 3,146
Gross profit 1,026 1,308 1,384 2,077
Net loss applicable to
common stock (4,031) (3,583) (3,755) (15,582)
Loss per common share $ (.16) $ (.14) $ (.15) $ (.61)
================================================================================
1994: March 31, June 30, September 30, December 31,
- --------------------------------------------------------------------------------
Revenues $ 1,487 $ 2,145 $ 1,463 $ 1,382
Gross profit 574 471 469 516
Extraordinary gain - - 128 703
Net loss applicable to
common stock (4,051) (3,402) (4,638) (3,385)
Loss per common share $ (.16) $ (.13) $ (0.19) $ (.13)
================================================================================
The third quarter of 1992 was restated to reflect the effect of implementing
the effect of fresh start reporting.
The net loss for the fourth quarter of 1993 includes a charge of $12.4 million
related to the provision for loss on the sale of assets to BBC.
14. ONGOING BUSINESS OPERATIONS
The accompanying consolidated financial statements have been prepared assuming
that the Company will continue as a going concern. The Company has a substantial
accumulated deficit, and has suffered recurring operating losses as well as cash
flow deficits that raise substantial doubts about its ability to continue as a
going concern. The financial statements do not reflect any adjustments that
might result from the outcome of this uncertainty.
Management does believe, however, that with the substantial improvement in its
debt structure, including its new revolving credit facility and the reduction in
general and administrative expenses, it will generate the necessary cash flow
not only to support its ongoing business operations but also to carry out oil
and gas property development activities in accordance with its business plans.
15. PRIOR PERIOD ADJUSTMENTS
In July 1994, the Company restructured and converted its BMO debt of
$4,652,000 to a non-recourse note secured only by proceeds, if any, which might
have been received from the NFG Litigation. This restructuring and conversion
was accounted for as an exchange transaction presented as an extinguishment of
debt in accordance with Emerging Issues Task Force Consensus No. 86-18 and
resulted in the recognition of an extraordinary gain, net of transaction costs
of $492,000, of $4,160,000 in the third quarter of 1994. In connection with
responding to comments from the Securities and Exchange Commission in connection
with a 1996 filing, the Company accepted the Securities and Exchange
Commission's determination that generally accepted accounting principles require
the Company to account for the restructuring and conversion of debt as a
troubled debt restructuring in accordance with Statement of Financial Accounting
Standards No. 15. As a result of this change, the financial statements for
September 30, 1994 through the current period reported have been restated to
restore the liability for the non-recourse BMO debt, including accrued interest,
and to reverse the extraordinary gain recognized in 1994. This
48
<PAGE>
restatement did not impact cash flow during the period September 30, 1994
through the current period reported. The Company did, however, upon resolution
of the NFG Litigation in April 1996, reflect a net gain from litigation
settlement of $7,100,000 and an extraordinary debt extinguishment gain of
$1,868,000, and made a final debt payment to BMO of $3,600,000. A summary of
the impact for 1994 is shown below (in thousands, except per share data).
December 31, 1994
----------------------
Reported Restated
-------- ---------
BALANCE SHEET
Total current liabilities $ 3,928 $ 3,765
Long term debt 1,150 6,020
Accumulated deficit (40,904) (45,611)
Total stockholders' deficit (39,004) (43,711)
Year Ended December 31,
1994
-----------------------
Reported Restated
-----------------------
STATEMENT OF OPERATIONS
General and administrative expense $ 1,747 $ 2,239
Interest expense 948 1,166
Income tax expense 180 17
Extraordinary gain 4,991 831
Net loss applicable to common stock (10,769) (15,476)
Net loss per share of common stock (0.42) (0.61)
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
In October 1992, the Company filed a Form 8-K regarding the change of its
independent accountants from BDO Seidman to Price Waterhouse. Subsequently, BDO
Seidman furnished a letter stating that it agreed with the statements contained
in the Form 8-K.
During 1994, there were no disagreements with the Company's independent
accountants regarding accounting or financial disclosure matters.
49
<PAGE>
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Board of Directors
The Company's restated Certificate of Incorporation provides for a Board
consisting of eight members elected for three year terms beginning January 21,
1992 and ending on January 21, 1995 or when their successors are duly elected
and qualified. On the effective date of the Plan, five such directors (the
"Senior Preferred Directors") were elected by holders of the Senior Preferred
and two (the "Common Stock Directors") were elected by holders of the Common
Stock, Old Preferred and Junior Preferred voting as a class. The remaining
director is the chief executive officer of the Company. During 1993, two
directors resigned, one Senior Preferred Director and the other a Common Stock
Director. To date no replacements have been elected. Of the Senior Preferred
Directors, two were elected on an unrestricted basis, one was subject to the
requirement that such director not be an affiliate of any holder of Senior
Preferred, and two were designated by Steinhardt. The Common Stock Directors
are required not to have been directors of TGX at the time it filed for
bankruptcy or be affiliated with any former TGX director. After the expiration
of the initial three year term, the term of all directors are for one year, and
all restrictions and requirements for selection of the Board are removed. As of
January 21, 1995, therefore, all eight directors are elected by all of the
stockholders voting in accordance with the Certificate of Incorporation of the
Company. Senior Preferred Stockholders maintain 95% of the voting power of all
stockholders, and, therefore, can elect all directors of the Company. However,
pursuant to the terms of the Senior Preferred Stock designation, if TGX fails
to pay six quarterly dividends then the Board of Directors is increased by two
members to ten and such additional two members are to be elected solely by the
Senior Preferred Stockholders. TGX has failed to pay such dividends and,
therefore, pursuant to the Certificate of Incorporation, at the next annual
meeting of stockholders, the Senior Preferred Stockholders voting alone are
entitled to elect two members to the Board of Directors. The Company cannot
determine when the next annual meeting of stockholders will be held and,
therefore, can make no determination as to when such additional board members
will be elected. The Board met on six occasions in 1994 and each current
director attended at least 75% of such meetings.
The members of the Board are:
<TABLE>
<CAPTION>
Served as Position, Prinicipal Occupation,
Director Business Experience and the
Name Age Since Directorships Held
---- --- --------- --------------------------------
<S> <C> <C> <C>
LARRY H. CARPENTER 47 1992 Chairman of the Board, President and Chief
Executive Officer of the Company since November
1992. From March 1992 he served as a consultant
to the Company until his election as President.
Prior thereto he was a senior executive with
Texas Oil & Gas Corp. from 1977 through
September 1990 and thereafter was engaged as an
independent oil and gas consultant.
MARK LIDDELL 40 1992 President of DLB Oil and Gas, Inc, a privately
owned independent oil and gas company located
in Oklahoma City, Oklahoma and previously
served as Vice President of DLB Energy
Corporation. Mr. Liddell also has a law degree
and has been a practicing attorney.
JOHN W. MASON 69 1992 President, Burnett Oil Company, Fort Worth,
Texas, a privately owned independent oil and
gas company.
KAREN RYUGO 35 1992 Vice-President of Concurrency Management
Corporation, a management company, and a
Principal in Wexford Capital Corporation, an
investment management company, both based in
New York. From 1988 until December 1994, a
Senior Research Analyst for Steinhardt
Management Company, Inc. Prior to 1988, she
served as an analyst at Stockbridge Partners
and as a research assistant at Montgomery
Securities.
</TABLE>
50
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C> <C>
R.J. SCHUMACHER 66 1992 President and Chief Executive Officer of
Texland Petroleum, Inc. a privately owned
independent oil and gas company. From June 1989
through March 1994, Mr. Schumacher also served
as Chairman and Chief Executive Officer of
Pride Refining, Inc., Fort Worth, Texas, the
general partner of Pride Companies, L.P., a
master limited partnership traded on the New
York Stock Exchange. Mr. Schumacher also
serves as a director of Aztec Manufacturing
Company, a publicly traded company.
JEFFREY E. SUSSKIND 41 1992 Principal of Strome, Susskind Investment
Management, L.P., an investment management
company in Santa Monica, California. Mr.
Susskind previously was an investment manager
with Kayne, Anderson & Co.
</TABLE>
Certain officers, directors and stockholders were required to timely file with
the Securities and Exchange Commission reports reflecting their ownership of the
Company's securities and any such change in owners. All persons required to file
reports have represented to the Company that they timely filed all required
reports and no further reports are required to be filed.
Committees
The current Committees of the Board of Directors consist of the Audit
Committee, the Compensation Committee and the Executive Committee. All non-
officer directors are members of the Audit, Compensation and Executive
Committees. In 1994, the Audit Committee met on one occasion, the Executive
Committee did not meet, and the Compensation Committee met on two occasions.
EXECUTIVE OFFICERS OF THE COMPANY
Presented below are the names, ages and positions held during the past five
years of the Company's executive officers as of March 28, 1995. Pursuant to the
By-Laws of the Company, officer serves at the pleasure of the Board of Directors
and may be removed, with or without cause, at any time.
Name Age Position
---- ---- --------
LARRY H. CARPENTER 47 See information as set forth
under "Board of Directors."
MICHAEL A. GERLICH 40 Mr. Gerlich was elected Vice
President and Chief Financial
Officer of the Company in
December, 1994. From January
1993 until joining TGX, he owned
and managed Chalk Hill
Resources, Inc., an independent
oil and gas investing and
financial consulting company.
Prior thereto, he was Executive
Vice President from January 1989
to December 1992 and Vice-
President of Finance from May
1982 to December 1988 for
Trinity Resources, Inc., an
independent public oil and gas
company.
51
<PAGE>
ITEM 11. EXECUTIVE COMPENSATION.
The following table sets forth the cash compensation paid to the Chief
Executive Officer and each of the most highly paid executive officers of the
Company for each of the last three years whose cash compensation for 1994
exceeded $100,000. For 1994, other annual compensation for Mr. Carpenter
includes for reimbursement of house expenses and for reimbursement of automobile
expenses.
<TABLE>
<CAPTION>
SUMMARY COMPENSATION TABLE (1)
LONG TERM COMPENSATION
ANNUAL COMPENSATION AWARDS
------------------- ------
Name and Other
Principal Annual Restricted Stock Options/ All Other
Position Year Salary($) Bonus($) Compensation($) Awards($) SARs(#) Compensation ($)
- --------- ---- -------- -------- ---------------- ---------------- -------- ----------------
<S> <C> <C> <C> <C> <C> <C> <C>
LARRY H. 1994 $175,000 $100,000(3) $26,062(3) N/A -0- -0-
CARPENTER 1993 $175,000 (3) $49,062(3) N/A N/A -0-
PRESIDENT/ CEO 1992 $160,667(2) N/A $19,913(3) 200,000 (4) N/A -0-
</TABLE>
1. The table above lists the compensation of the CEO the only employee who
received in excess of $100,000 in total compensation for 1994.
2. Includes amounts paid to Mr. Carpenter as a consultant to the Company prior
to his election as President and Chief Executive Officer of the Company in
November, 1992.
3. Excludes perquisites and other benefits, unless the aggregate amount of
such does not exceed the lesser of either $50,000 or 10% of the total
annual salary and bonus reported for the named executive officer. For Mr.
Carpenter, it includes housing, automobile and moving expense allowances
from the period of time when Mr. Carpenter became a consultant to the
Company, as well as such expenses after Mr. Carpenter was elected President
of the Company. See "Employment Agreements".
4. Includes the award of 200,000 shares of Series A Preferred Stock which was
forfeitable, in part, if Mr. Carpenter ceased to be an employee of the
Company prior to March 1995. As of December 31,1994, there was no trading
in the Series A Senior Preferred Stock and, therefore, the Company was not
able to determine a market value for such stock. For stock compensation
purposes, the Company valued these shares at $1.50 per share, based on an
internal estimate of Company net assets as of October 2, 1992 (fresh start
reporting). Of such award, 133,333 shares ceased to be subjected to
forfeiture as of December 31,1994 and the remaining 66,667 shares ceased
being subject to forfeiture on March 31, 1995.
Employment Agreements
Larry H. Carpenter, Chairman of the Board, President and Chief Executive
Officer of the Company, entered into an employment agreement (the "Employment
Agreement") with the Company in March 1992. Pursuant to the Employment
Agreement, for the period through November 1992, Mr. Carpenter acted as a
consultant to the Company and had an option to become a full-time employee,
President and member of the Board of Directors. In November 1992, Mr. Carpenter
exercised such option and, at that time, was elected President of the Company
and, pursuant to the Articles of Incorporation, became a member of the Board of
Directors. Pursuant to the Employment Agreement, for a period of three years
ending March 30, 1995, Mr. Carpenter received compensation equal to $175,000 per
annum, plus discretionary bonuses as determined by the Board of Directors. For
1993, the Board of Directors did not grant a discretionary bonus. However, in
February 1994, the Board of Directors granted a bonus of $100,000 to Mr.
Carpenter in connection with his efforts in consummating the sale of the
Company's New York and Ohio properties. In addition, Mr. Carpenter received
200,000 shares of the Company's Series A Senior Preferred Stock which vested
over the term of the Employment Agreement. The Employment Agreement also
provided Mr. Carpenter with certain living expense allowances, as well as
benefits relating to moving expense, health and life insurance, club membership
and use of an automobile.
In December 1991, the Company entered into an employment agreement with Mr.
Joe W. Cluck formerly Vice President and Chief Financial Officer of the Company.
The employment agreement provided that he be employed by TGX as Vice President
and Chief Financial Officer at a monthly salary of $9,175. Mr. Cluck's agreement
could be
52
<PAGE>
terminated at any time and entitles him to six months severance pay upon
termination of such agreement. In June, 1994, Mr. Cluck resigned from the
Company and received his severance payment.
Employees Stock Options and Restricted Stock Plans
The Company had adopted two stock option plans: a Non-Qualified Stock Option
Plan and an Incentive Stock Option Plan, each of which are incentive plans
administered by the Board of Directors. Both of these plans were terminated in
1991, and while options previously issued are still valid, no new options can be
issued.
During 1994, no options were granted nor exercised pursuant to these plans.
Compensation of Directors
Each non-employee member of the Board received a fee of $1,500 per month
through June 1994 and $833 thereafter plus a meeting fee of $500 per day through
June 1994 and $1,000 per day thereafter, subject to forfeiture on a six-month
prospective basis if a director attends less than 75% of the meetings, and
reimbursement for reasonable travel expenses incurred in conjunction with
meetings, with air fare not to exceed the rate for a full-fare coach seat.
Indemnification of Officers and Directors
The Company's Certificate of Incorporation provides that the Company shall
indemnify the officers and directors to the fullest extent allowed by Delaware
Law. In addition, the Company has entered into indemnification agreements with
certain Directors and officers ("Indemnification Agreement") to provide certain
additional protection in the event actions are filed against them in their
capacities as directors and officers. The Company proposes to enter into an
Indemnification Trust Agreement which establishes a trust fund (the "Fund"),
administered by a trustee, available to pay indemnification claims made by the
directors and officers to the extent the Company has not paid such claims. To
date the Company has not established such Fund.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
As of March 28, 1995, the Company had no "parent" as that term is defined in
regulations promulgated under the Securities Exchange Act of 1934, as amended.
Security Ownership of Management
The following table sets forth, as of March 28, 1995, the amount of the
Company's Common Stock or Series A Senior Preferred Stock beneficially owned by
each of its directors, each executive officer named in the Summary Compensation
Table, and all directors and executive officers as a group, based upon
information obtained from such persons.
<TABLE>
<CAPTION>
Name of Amount and Nature of
Individual or Group Beneficial Ownership
- ---------------------------------------------------------------------------------------
Options Percent
Sole Voting and Exercisable of
Investment Power Within 60 Days Class /1 //
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C>
Larry H. Carpenter/2// 200,000 Series A -0- 2.3%
Mark Liddell -0- -0- -
John W. Mason 22,366 Series A -0- -
Karen Ryugo -0- -0- -
R. J. Schumacher 59,462 Common -0- -
Jeffrey E. Susskind -0- -0- -
All executive officers 222,366 Series A
and directors as a 59,462 Common -0- -
group (7 persons)
- ---------------------------------------------------------------------------------------
</TABLE>
1/ Unless otherwise indicated, the holders have sole voting and investment
powers. Unless otherwise stated, the percentage is less than one percent.
53
<PAGE>
2/ Mr. Carpenter's shares are subject to forfeiture pursuant to the terms of
his employment agreement. See "Employment Agreement". As of March 28,1995,
all shares have been vested and are no longer subject to forfeiture.
Security Ownership of Certain Beneficial Owners
The following table sets forth certain information regarding each person
known by the Company owning or entitled to own as the beneficial owner, more
than 5% of the Company's outstanding Common Stock, Senior Preferred or Old
Preferred Stock as of March 28, 1995.
<TABLE>
<CAPTION>
Amount
Beneficially Percent
Name and Address of Beneficial Owner Class Owned of Class
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Liberty National Bank and Trust Company Common 3,136,986(1) 12.4%
of Oklahoma City, Escrow Agent UA,
November 18, 1985, Templeton Energy,
Inc./Temex Energy, Inc. and Escrow
Agent for the benefit of certain
claimants of Amarex, Inc.
P.O. Box 25848
Oklahoma City, Oklahoma 73125
Paragon Resources, Inc. Common 3,459,521(2) 13.7%
401 Market Street, Suite 701
Shreveport, Louisiana 71101
1987 Humphrey Trust Common 3,456,252(3) 13.7%
Carl J. Udouj, Trustee
520 South 14th
Forth Smith, Arkansas 72901
Gaylon D. Simmons and Old
Gloria Annette Turner Simmons Preferred 300.000 100.0%
905 East Main Street
Jonesboro, Louisiana 71251
Steinhardt Partners, L.P. Senior
and certain affiliates Preferred 1,692,796(4)(5) 19.4%
605 Third Avenue
New York, NY 10158
The AIF-Lion Group
c/o Apollo Advisors, L.P.
Two Manhattanville Road Senior
Purchase, N.Y. 10577 Preferred 1,823,000(6) 21.0%
- -----------------------------------------------------------------------------------------------
</TABLE>
(1) In connection with its acquisition of Amarex, Inc. which was consummated on
December 5, 1985, the Company issued 11,475,000 shares of Common Stock into
escrow with Liberty National Bank and Trust Company of Oklahoma City as
escrow agent. Such shares are held by the escrow agent for the benefit of
various classes of creditors of Amarex and its affiliates entitled to
receive the shares under a Plan of Reorganization confirmed in Amarex's
bankruptcy proceeding, and the shares have been and will continue to be
distributed by the escrow agent from time to time as the various creditors'
claims are adjudicated and allowed by the Bankruptcy Court. As of March
28,1995, 3,136,986 shares remained in escrow. Pursuant to the agreement
governing the administration of the escrow account, the escrow agent has
agreed to cause the escrowed shares to be voted at any annual or special
stockholders' meeting in accordance with the instructions of the Company.
54
<PAGE>
(2) Includes 3,456,252 shares owned of record and beneficially by Paragon
Resources, Inc. ("Paragon") and an aggregate 3,269 shares owned of record or
beneficially by certain affiliates of Paragon. With respect to the 3,456,252
shares owned by Paragon, Paragon may be deemed to share the power of voting
and disposition with Majestic Energy Corporation ("Majestic"), which owns
approximately 95% of the voting securities of Paragon. All of the capital
stock of Majestic is owned by the 1987 Humphrey Trust established by W. M.
Templeton for the benefit of J. C. Templeton's grandchildren (the "Humphrey
Trust").
(3) Includes the 3,456,252 shares owned of record by Paragon with respect to all
of which the Humphrey Trust may be deemed to be the beneficial owner by
reason of its voting control of Majestic.
(4) Pursuant to the terms of the Plan, certain holders of the Company's
outstanding Senior Subordinated Notes are entitled to receive shares of the
Company's Senior Preferred Stock. Such shares were to be issued following
the order of substantial consummation by the Bankruptcy Court, which became
effective in October 1992. See Item 1. "Business -Reorganization
Proceeding". As a result of a fee dispute with the Indenture Trustee for
holders of the Senior Subordinated Notes ("Trustee"), those shares were not
issued to the beneficial holders as of December 31, 1994. However in late
1994, the dispute with the Trustee was settled and the Senior Preferred
Stock shares were distributed in 1995.
(5) Pursuant to the Plan, Steinhardt is entitled to receive 1,692,796 shares, or
19.4% of the to be outstanding shares of the Senior Preferred. See
"Business-Reorganization Proceeding."
(6) Such information has been supplied to the Company pursuant to a Schedule 13D
filed with the Securities and Exchange Commission on December 31,1994, by
AIF II, L.P., a Delaware limited partnership and Lion Advisors, L.P., a
Delaware limited partnership (collectively the "Reporting Persons"). Such
Reporting Persons may together constitute a "group" within the meaning of
Rule 13d-5 under the Securities Exchange Act of 1934, as amended.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The Company had substantial transactions with Paragon Resources, Inc.
("Paragon") a Delaware corporation which is engaged in the oil and natural gas
business for its own account and for the account of drilling programs it has
sponsored and which it may sponsor in the future. Paragon and its affiliates are
the owners of approximately 14% of the Company's outstanding Common Stock. Mr.
W. M. Templeton, a former Director of the Company, is an officer of Paragon and
Majestic which owns 95% of the common stock of Paragon. In addition, 100% of the
common stock of Majestic is owned by the Humphrey Trust, an Arkansas trust
established by W. M. Templeton. Given these relationships, there is a potential
conflict of interest between the Company and Paragon in connection with the
operations of oil and natural gas properties and other matters.
In the past, the Company's transactions with Paragon and its affiliates
included the offering of interests in and drilling of wells, the sponsorship of
the sales of interests in limited partnerships, and furnishing administrative
services by both parties. Prior to the formation of the Company, Paragon's
principal business was sponsoring limited partnerships engaged in the
exploration for oil and natural gas. As part of Paragon's contribution to the
formation of the Company, Paragon transferred substantially all of its personnel
to the Company. Further, Paragon agreed to sell substantially all of its
undeveloped oil and natural gas leasehold acreage to the Company at Paragon's
investment cost in such acreage and Paragon agreed that the Company could be a
co-sponsor in the sales of limited partnership interests which Paragon intended
to sponsor solely for its own account. As a result of such co-sponsorship, the
Company and Paragon were co-general partners of two public limited partnership
drilling programs organized in 1981 and dissolved in 1994. Also, as part of the
formation of the Company, the parties agreed that the Company would manage
certain Paragon properties for a fee and would provide certain administrative
services to Paragon and its affiliates. Amounts billed by the Company, net of
company revenue offsets, to Paragon and its affiliates during 1994 totaled
$151,000 for joint interest operations and other costs. As of December 31, 1994,
the Company's records indicate that Paragon and certain of its affiliates owed
the Company in excess of $2,313,000 for uncollected billings. An allowance for
possible uncollectibility has been established for the amount in excess of
$286,000.
55
<PAGE>
Litigation Against Former Directors and Officers of Paragon
In 1992, the Company commenced several actions in the Bankruptcy Court
against Paragon, J. C. Templeton (former President, Chief Executive Office and
Director), W. M. Templelon (the son of J. C. Templeton, who was also a former
director), and a number of other former directors of the Company for violations
of their fiduciary obligations, gross negligence, mismanagement and usurpation
of corporate opportunities.
In October, 1992, the action against two of the former directors of the
Company was dismissed. Motions to dismiss were filed by the other directors but,
prior to the time such motions could be heard, a motion was made to remove the
case from the jurisdiction of the Bankruptcy Court. In 1993, the Federal
District Court sitting in Alexandria, Louisiana, agreed to the removal of the
jurisdiction of the Bankruptcy Court in these cases and, determined that all
further proceedings would be heard before such Court.
In April 1992, certain former directors brought a separate action in the
Delaware Chancery Court alleging that (i) the Company's claims were barred by
the statute of limitations, (ii) the Company's Articles and By-Laws exonerated
these former directors, and (iii) the former directors were entitled to
indemnification and advancement of legal fees by the Company. The Company
intends to vigorously defend against the claims made in the Delaware action.
56
<PAGE>
PART IV.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(A) Index to Financial Statements
1. Financial Statements:
The following financial statements of the Company are included in Part II,
Item 8.
(a) Reports of Independent Accountants
(i) Price Waterhouse LLP
(b) Financial Statements of TGX Corporation (the Registrant) and
Subsidiaries
(i) Consolidated Balance Sheet as of December 31, 1994 and 1993
(ii) Consolidated Statement of Operations for the years ended
December 31, 1994 and 1993 and the two periods January 1, 1992
through October 1, 1992 and October 2, 1992 through December 31,
1992.
(iii)Consolidated Statement of Cash Flows for the years ended
December 31, 1994 and 1993 and the two periods January 1, 1992
through October 1, 1992 and October 2, 1992 through December 31,
1992.
(iv) Notes to Consolidated Financial Statements
2. Financial Statement Schedules:
None required.
3. Exhibits:
Exhibit 2.1 Amended Plan of Reorganization and Disclosure Statement as
revised and filed by the Company, as debtor-in-possession, on
January 7, 1992. (Incorporated by reference to Exhibit 2.1 of
the Registrant's Current Report on Form 8-K dated February 4,
1992, File No. 1-10201.)
Exhibit 2.2 Order Confirming Amended Plan of Reorganization dated
January 7, 1992. (Incorporated by reference to Exhibit 2.2 Of
the Registrant's Current Report on Form 8-K dated February 4,
1992, File No. 1-10201. )
Exhibit 2.4 Stock Sale and Purchase Agreement by and between LEDCO
Acquisition Company, Inc. and the Company dated as of December
31, 1991. (Incorporated by reference to Exhibit 2.4 of the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1991, File No.0-10201).
Exhibit 2.5 Stock Purchase and Sale Agreement between Gaylon D. Simmons and
Gloria Annette Turner Simmons and Templeton Energy, Inc. dated
October 13, 1986 (Incorporated by reference to Exhibit 2.1 of
the Registrant's Current Report on Form 8-K dated December 1,
1986, File No. 0-10201).
Exhibit 3.1 Restated Certificate of Incorporation of the Company.
(Incorporated by reference to Exhibit 3.1 of the Registrant's
Annual Report on Form 10-K for the year ended December 31,
1991, File No. 0-10201).
Exhibit 3.2 Amended and Restated By-Laws of the Company. (Incorporated by
reference to Exhibit 3.2 Registrant's Annual Report on
Form 10-K for the year ended December 31, 1991,
File No. 0-10201).
57
<PAGE>
Exhibit 3.3 Rights Agreement dated as of October 4, 1988 between the
Company and American Stock Transfer Trust Company (Incorporated
by reference to Exhibit C.1 of the Registrant's Current Report
on Form 8-K dated October 11, 1988).
Exhibit 4.1 Specimen Certificate representing shares of Common Stock
(Incorporated by reference to Exhibit 4.1 of the Registrant's
Annual Report on Form 10-K for the year ended December 31,
1985, File No. 0-10201).
Exhibit 4.2 Specimen Certificate representing shares of Old Preferred Stock
(Incorporated by reference to Exhibit 4.2 of the Registrant's
Annual Report on Form 10-K for the year ended December 31,
1986, File No. 0-10201) .
Exhibit 4.3 Specimen Certificate representing shares of Senior Preferred
Stock. (Incorporated by reference to Exhibit 4.3 of the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1991, File No. 0-10201).
Exhibit 10.1 Amended and Restated Credit Agreement effective as of February
1,1992 between the Company and the Bank of Montreal and the
First Amendment thereto. (Incorporated by reference to Exhibit
10.1 of the Registrant's Annual Reporting Form 10-K for the
year ended December 31, 1991, File No. 0-10201).
Exhibit 10.2 Amended and Restated Security Agreement effective as of
February 1, 1992 between the Company and the Bank of Montreal.
(Incorporated by reference to Exhibit 10.2 of the Registrant's
Annual Report on Form 10-K for the year ended December 31,
1991, File No. 0-10201).
Exhibit 10.3 Amended and Restated Security Agreement (Partnerships)
effective as of February 1, 1992 between the Company and the
Bank of Montreal. (Incorporated by reference to Exhibit 10.3 of
the Registrant's Annual Report on Form 10-K for the year ended
December 31, 1991, File No. 0-10201).
Exhibit 10.4 Amendment and Restated Stock Pledge Agreement effective as of
February 1,1992 between the Company and the Bank of Montreal.
(Incorporated by reference to Exhibit 10.4 of the Registrant's
Annual Report on Form 10-K for the year ended December 31,
1991, File No. 0-10201).
Exhibit 10.5 Amended and Restated Pledge of Secured Notes effective as of
February 1, 1992 between the Company and the Bank of Montreal.
(Incorporated by reference to Exhibit 10.5 of the Registrant's
Annual Report on Form 10-K for the year ended December 31,
1991, File No. 0-10201).
Exhibit 10.6 Promissory Note (Term Loan A) in the amount of $15,600,000
effective as of February 1, 1992 executed by the Company to the
order of the Bank of Montreal. (Incorporated by reference to
Exhibit 10.6 of the Registrant's Annual Reporting Form 10-K for
the year ended December 31,1991, File No. 0-10201).
Exhibit 10.7 Promissory Note (Term Loan B) in the amount of $10,000,000
effective as of February 1, 1992 executed by the Company to the
order of the Bank of Montreal. (Incorporated by reference to
Exhibit 10.7 of the Registrant's Annual Reporting Form 10-K for
the year ended December 31, 1991, File No. 0-10201).
Exhibit 10.8 Promissory Note (Term Loan C) in the amount of $1,250,000
effective as of February 1, 1992, executed by the Company to
the order of the Bank of Montreal. (Incorporated by reference
to Exhibit 10.8 of the Registrant's Annual Reporting Form 10-K
for the year ended December 31, 1991, File No. 0-10201).
Exhibit 10.9 Promissory Note (Revolving Credit Note) in the amount of
$500,000 effective as of February 1,1992, executed by the
Company to the order of the Bank of Montreal. (Incorporated by
reference to Exhibit 10.9 of the Registrant's Annual Reporting
Form 10-K for the year ended December 31, 1991, File No. 0-
10201).
58
<PAGE>
Exhibit 10.10 Restricted Stock Award Plan (Incorporated by reference to
Exhibit 13.51 of the Registrant's Registration Statement No. 2-
70911 on Form S-1 effective March 4, 1981).
Exhibit 10.11 Non-Qualified Stock Option Plan (Incorporated by reference to
Exhibit 13.50 of the Registrant's Registration Statement No. 2-
70911 on Form S-1 effective March 4, 1981).
Exhibit 10.12 Incentive Stock Option Plan (Incorporated by reference to
Exhibit A of the Registrant's 1981 Proxy Statement dated
April 26, 1982).
Exhibit 10.13 Employment Agreement dated December 23, 1991 between the
Company and Ronald E. Grappe. (Incorporated by reference to
Exhibit 10.13 of the Registrant's Annual Report on Form 10-K
for the year ended December 31, 1991, File No. 010201).
Exhibit 10.14 Employment Agreement dated December 23,1991 between the Company
and Joe W. Cluck. (Incorporated by reference to Exhibit 10.14
of the Registrant's Annual Report on Form 10-K for the year
ended December 31, 1991, File No. 0-10201).
Exhibit 10.15 Form of Indemnification Agreement to be entered into by and
among the Company and each officer and director. (Incorporated
by reference to Exhibit 10.15 of the Registrant's Annual Report
on Form 10-K for the year ended December 31,1991, File No. 0-
10201).
Exhibit 10.16 Form of Indemnification Trust Agreement. (Incorporated by
reference to Exhibit 10.16 of the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1991, File No. 0-
10201).
Exhibit 10.17 Promissory Note (Term Loan D) in the amount of $194,750
effective October 1,1992, executed by the Company to the order
of Bank of Montreal. (Incorporated by reference to Exhibit A of
Form 8-K dated October 2, 1992, File No. 0-10201).
Exhibit 10.18 Personal Service and Employment Agreement Dated March 30,1992
between the Company and Larry H. Carpenter. (Incorporated by
reference to Exhibit 10.18 of Form 10-K for the year ended
December 31, 1992, File No. 0-10201).
Exhibit 10.19 Purchase and Sale Agreement between TGX Corporation and Belden
and Blake Corporation dated as of December 17, 1993.
(Incorporated by reference to Exhibit C of Form 8-K dated
January 14, 1994, File No. 0-10201).
Exhibit 10.20 United Forbearance Agreement between TGX Corporation and Bank
of Montreal dated as of January 10,1994. (Incorporated by
reference to Exhibit C of Form 8-K dated January 14, 1994, File
No. 0-1-10201).
Exhibit 10.21 Second Amended and Restated Credit Agreement between the
Company and BMO Financial, Inc. dated as of July 13,1994.
(Incorporated by reference to Exhibit 10.1 of the Registrant's
Form 8-K dated July 13, 1994).
Exhibit 10.22 Amended and Restated Credit Agreement between the Company and
Bank One, Texas, N.A. dated as of July 13, 1994. (Incorporated
by reference to Exhibit 10.4 of the Registrant's report on Form
8-K dated July 13, 1994).
Exhibit 18 Letter regarding Change in Accounting Principles. (Incorporated
by reference to Exhibit 18 of Form 10-K for the year ended
December 31,1992, File No. 0-10201).
(b) Reports on Form 8-K for the quarter ended December 31, 1994: None.
59
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Report to be signed on
its behalf by the undersigned "hereunto duly authorized.
TGX Corporation
(Registrant)
Signature Title Date
--------- ----- ----
By: /s/ MICHAEL A. GERLICH Vice President and
---------------------- Chief Financial Officer February 25, 1997
Michael A. Gerlich
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
By: /s/ MICHAEL A. GERLICH Vice President and
---------------------- Chief Financial Officer February 25, 1997
Michael A. Gerlich
By: /s/ JEFFREY E. SUSSKIND Director February 25, 1997
-----------------------
Jeffrey E. Susskind
By: /s/ DAVID H. SCHEIBER Director February 25, 1997
---------------------
David H. Scheiber
60
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> JAN-01-1994
<PERIOD-END> DEC-31-1994
<CASH> 676
<SECURITIES> 0
<RECEIVABLES> 4,110
<ALLOWANCES> 2,400
<INVENTORY> 0
<CURRENT-ASSETS> 2,446
<PP&E> 10,564
<DEPRECIATION> (3,307)
<TOTAL-ASSETS> 10,676
<CURRENT-LIABILITIES> 3,765
<BONDS> 0
44,602
431
<COMMON> 290
<OTHER-SE> (44,432)
<TOTAL-LIABILITY-AND-EQUITY> 10,676
<SALES> 4,802
<TOTAL-REVENUES> 6,477
<CGS> 3,188
<TOTAL-COSTS> 3,188
<OTHER-EXPENSES> 3,653
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 1,166
<INCOME-PRETAX> (1,530)
<INCOME-TAX> 17
<INCOME-CONTINUING> (1,547)
<DISCONTINUED> 0
<EXTRAORDINARY> 831
<CHANGES> 0
<NET-INCOME> (15,476)
<EPS-PRIMARY> (0.61)
<EPS-DILUTED> (0.61)
</TABLE>
